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UNS Energy Corporation (NYSE:UNS)

Q3 2013 Earnings Call

November 6, 2013, 12:00 PM ET

Executives

Chris Norman - Manager, Investor Relation

Paul Bonavia - Chairman of the Board and Chief Executive Officer

Kevin Larson - Senior Vice President, Chief Financial Officer and Treasurer

David Hutchens - President and Chief Operating Officer

Analysts

Kevin Cole - Credit Suisse

Paul Fremont - Jeffries

Maury May - Wellington Shields

Brian Russo - Ladenburg Thalmann

Operator

Good morning, and welcome to the UNS Energy third quarter 2013 earnings conference call. Today's call will be hosted by Paul J. Bonavia, UNS Energy Chairman and Chief Executive Officer. (Operator Instructions) Now, I would 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 third quarter financial results. Joining me on the call today are, Paul Bonavia, UNS Energy's Chairman and Chief Executive Officer; and Kevin Larson, UNS Energy's Senior Vice President and CFO.

Before Paul and Kevin begin the remarks, 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 the 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 our prepared remarks, we will open up the call for Q&A

Now, I'd like to turn it over to Paul.

Paul Bonavia

Thanks, Chris, and thank you all for joining us today. This morning, we reported that UNS Energy's net income for the third quarter 2013 was $68 million or $1.62 per share on a fully diluted basis. By contrast, in the third quarter of 2012, we reported net income of $50.7 million or $1.21 per diluted share.

Our third quarter results reflect TEP's new base rates, which became effective July 1. The improvement in TEP's retail margin revenues was partially offset by an increase in operations and maintenance expense related in part to unplanned generating plant outages.

And we have better visibility into our financial forecast. We're providing 2013 earnings guidance of $2.95 to $3.10 per diluted share. If you exclude the $0.22 of adjustments related to TEP's rate case that we recorded in the second quarter, our 2013 guidance range would be approximately $2.73 to $2.88. For 2014, we estimate earnings per share to be in a range of $3.15 to $3.45. And in 2015, we expect earnings to grow by approximately 4% from the 2014 midpoint.

The successful execution of our long-term resource strategy, the continued reduction in TEP's capital lease expense and the new and pending rate structures at TEP and UNS Electric, give us confidence that we can grow earnings over the next two years in spite of various cost pressures. Also we expect board to evaluate the dividend in February, taking into account our current financial projections. The current stated policy is to target a payout ratio of 60% to 70% of net income.

Now turning to our long-term resource strategy. We're making significant progress toward diversifying our generating fuel mix. During the third quarter, we committed to purchase approximately 35% of the capacity of Springerville Unit 1 that is currently leased by TEP. TEP will pay approximately $65 million or $478 per kilowatt for ownership of 137 megawatt of continuous operating capability.

The purchase price is consistent with the result of the formal appraisal proceeding that was completed last year. Upon the closing of these purchases in late 2014, we'll own 49.5% of Springerville 1 and that includes the 14% that TEP currently owns.

Another important component of our resource strategy is the San Juan Generating Station. In September, the New Mexico Environmental Improvement Board approved the current plant that would lead to the retirement of San Juan Units 2 and 3 by the end of 2017, as well as the installation of selective non-catalytic reduction or SNCR technology on Units 1 and 4 by early 2016.

The plant still requires approval by the EPA. PNM expects the EPA approval process to take approximately 12 months. The book value of TEP share of Unit 2 was $114 million as of September 30, 2013. TEP estimates a share of capital to install SNCR on Unit 1, would be about $35 million.

As we reported in September, TEP is in exclusive negotiations to purchase Gila River Unit 3, a 550 megawatt gas-fired combined-cycle plant located in Gila Bend, Arizona. The addition of a modern gas-fired resource provides us with most flexibility to meet peak demand and integrate cost effective renewable resources into our system.

We're currently evaluating a structure, in which TEP would own about 400 megawatts of the plant, it's about 73%, and UNS Electric would own the remaining 150 megawatt or about 27%. If the purchase of Gila River Unit 3 is completed, TEP expects the usage share of the capacity, first of all to replace the 200 megawatt approximate reductions in coal-fired capacity from Springerville Unit 1 in 2015.

And secondly, to replace the expected retirement of San Juan Unit 2 in late 2017, of which TEP's current ownership is a 170 megawatts. If UNS Electric does purchase a portion of the plant, we'll seek ACC approval to differ certain class related to the plant, until they can be recovered from customers and similar to the regulatory treatment APS is receiving on the Four Corners transaction.

Now, moving to regulatory matters. In September, UNS Electric, the ACC staff and other parties reached the settlement agreement in UNS Electric's pending rate case. The terms of the settlement included non-fuel base rate increase of $3 million or 2% based on an original cost rate basis, $212 million. It's an ROE of 9.5%, a return on the fair value increment is 50 basis points and a capital structure of 53% equity and 47% debt.

The settlement also includes a transmission cost adjuster mechanism that would allow retail rates to include transmission cost, reflecting the approved FERC rate as well as also including in this settlement a lost fixed cost recovery mechanism designed to recover non-fuel cost that would otherwise go unrecovered due to lost sales attributed to energy efficiency and to distributed generation. Hearings before the Administrative Law Judge, concluded in late September, and we're hopeful that the new rates will take effect by January 1, 2014.

Earlier this week, TEP and UNSE filed comments in APS' net metering docket, which is expected to be discussed in an open meeting on November 13. Arizona's net metering rules have created in equities that need to be corrected. And soon, we believe APS' proposals would mitigate on fair cost shifting and assure that all customers contribute their share of the cost to operate and maintain the electric grid.

And in September, you know that the ACC voted to close the docket related to retail competition. We appreciate the commission's diligence and reviewing all the issues raised in this proceeding, we continue to work on how we can offer our customers more choices within the current regulated framework.

Finally, I'd like to touch on our local economy. Economic recovery is taking hold in Arizona, albeit slowly. The recovery is evidenced by the customer growth in our service territories, which is approaching 1% per year. Vacancy rates in the industrial office and retail sectors in Tucson all declined during the third quarter. While the housing market in September continue to show improvement with an increase in closings of about 2.7% and an increase in the median selling price of about 7.6%.

And in September, the University of Arizona's Economic and Business Research Center updated their long-term economic forecast. They still project that Arizona's economic growth will outpace the national average for most indicator, as it has in the great majority of years since World War II. And they expect local recovery to gain momentum in 2014 and '15.

And final thing to comment on is the proposed Rosemont copper mine. There is no significant update at this time, but I know that people follow the progress of it on the website of the parent company, Augusta Resources. According to their published materials, they project mine construction to begin in early 2014 and production to commence in 2016. And on that score, I'd like to note that our earnings growth target for 2015, that I mentioned earlier, does not include sales to Rosemont mine.

So with that, I will turn it over to Kevin, who will present additional detail. Kevin?

Kevin Larson

Thank you, Paul, and thanks to everyone for joining us today. Again, into a few of the key drivers for UNS Energy's third quarter and year-to-date results, before we get into earnings guidance and then the Q&A.

If you'd like to follow along, please refer to Slide 2 of the presentation that was furnished in 8-K this morning and posted on our website. The slide shows the factors that impacted earnings between the third quarter of 2012 level of $1.21 per share and the third quarter 2013 level of $1.62. As you can see from Slide 2, there are various small puts and takes that tend to net out and that the primary factor moving UNS from a $1.21 to $1.62 is the $0.42 improvement in TEP's retail margin, which is a primarily a result of the rate relief that was effective July 1, 2013.

Turning to Slide 3. On a year-to-date basis, that's very similar story. Earnings were up $0.69 as a result of the higher retail margin and also $0.22 for one-time items recorded in the second quarter of this year related to TEP's rate case.

Before I discuss earnings guidance, I will touch on retail sales. In the third quarter of 2013, TEP's total retail sales were 2,909 gigawatt hours, a 1.1% above the third quarter of 2012. Cooling degree days in the third quarter were 8.9% higher than last year, and compared to normal weather patterns, we estimate the third quarter benefited pre-tax margins for the company by approximately $3 million. On a year-to-date basis, we estimate weather normalized sales were approximately nine-tenth-of-a-percent below the beginning of the 2012 weather normalized sales volume.

Now turn to earnings guidance. As we indicated in our press release and other materials filed this morning, we have provided earnings guidance for 2013, 2014 as well as providing earnings growth estimate for 2015.

First we will discuss 2013, which is shown on Slide 4. Given the results for the first three quarters of this year and our outlook for the fourth quarter, we estimate that 2013 diluted earnings will fall within the range of $2.95 to $3.10 per share. We reported earnings of $0.18 in the fourth quarter of 2012, we expect to exceed that level in Q4 of 2013.

The factors in the fourth quarter of this year taking us from the year-to-date earnings of $2.72 to our guidance range include the impacts of the rate increase at Tucson Electric Power Company, declining capital lease expense and those items were partially offset by higher O&M. Also recall that in the fourth quarter of 2012, we had a $4.5 million write-off related to transmission asset and that equates to roughly $0.07 per diluted share.

Our 2013 guidance of $2.95 to $3.10 is what we anticipate to achieve on a GAAP basis and that's what we tend to show our guidance. However, if you do adjust for the $0.22 rate case one-time items recorded in Q2, as I previously mentioned and also Paul touched on, 2013 earnings guidance would be $2.73 to $2.88 per diluted share.

Now I would like to touch base on our consolidated base O&M and that's shown on Slide 5. You can see our estimate for 2013 is $282 million and that's higher than our initial budget level of $273 million. Most of that is due to the unplanned outages, which on a year-to-date basis costs us approximately $4 million. We also rescheduled the maintenance, and this was plant maintenance. A $1 million plant maintenance outage at our [ph] San facility. We moved that from 2014 into 2013. And then we also had another factor that came into play, is there's some various severance costs that the company absorbed.

Looking at 2014, the 2014 base O&M range of $2.88 to $2.90 is driven by planned outage schedule. As you recall, our planned outage schedule varies year-to-year, 2014 happens to be a heavy outage period. To provide some context and as shown on the slide, 2013 has approximately $11 million of planned outages, while 2014 is expected to have approximately $19 million of planned outage O&M, that's $8 million higher. And then for 2015, we're targeting O&M growth of about 2%. That's kind of consistent with our story and how we've been able to control O&M historically.

Now turning to Slide 6. We will summarize our high level assumptions supporting 2014 guidance of $3.15 to $3.45 per diluted shares. These assumptions include on a weather normalized basis, we expect 2014 retail sales to be flat to 2013 at just over 9,100 gigawatt hours. Even though we estimate customer growth of approximately 1%, the effects of energy efficiency and distributed generation are offsetting some of the related sales growth.

2014 results will also reflect a full year of TEP's base rate increase that was effective July 1 of this yea. And we estimate TEPs total retail margin revenues to be in the range of $610 million to $615 million, that's compared with an estimate for 2013 of $585 million to $587 million.

And as Paul mentioned earlier, we anticipate having new range for UNS Electric. That should be in effect in January of 2014. The non-fuel base rate increase, including the settlement is $3.2 million. And as I pointed our earlier, when I talked about O&M, the O&M range for '14 is $288 million to $290 million.

Another item that supports, helps our earnings in 2014 is TEP's capital lease expense, as interest and amortization will continue to decline, as we're at the backend of many of these leases. We estimate lease expense will be $26 million in 2014. That's $14 million below the level in 2013. And finally, 2014 will be affected by new money financing assumptions.

If you continue on to Slide 7, we've outlined our high-level financing assumptions. We see the need for approximately $500 million of external financing over the next two years. Our planned capital expenditures of TEP will average approximately $500 million per year in 2014 and 2015, which includes purchases of Gila River Unit 3 and 35% of Springerville Unit 1. And we currently own 14% of Springerville Unit 1 and we anticipate ownership percentage up to 49.5% in 2015.

To finance these investments and other capital expenditures, we expect to issue $350 million of new debt. Of that, $250 million would be raised at the Tucson Electric Power Company level. And we also anticipate that UNS will issue approximately $150 million of new equity. UNS would contribute the equity into Tucson Electric Power Company.

The equity offering and the anticipated future earnings will support an equity level at TEP of approximately 44%, which is similar to the 43.5% authorized in TEP's recent rate case. With this new equity financing, we expect our credit metrics to remain strong and supportive of our current credit ratings.

As for the timing of these financings, we expect debt offering to occur in the second half of 2014, at least the majority of it. The type of debt, whether it's tax-exempt, taxable, the maturity, and the specific timing will depend on capital market conditions.

We plan to issue equity sometime between April 2014 and the middle of 2015, so June of 2015. Our specific approach to issue equity is yet to be determined. And we are considering various methods, including a dribble or an ATM program, a forward-sale or a more traditional same-day transaction.

Now, moving to Slide 8. We provide the assumptions that support earnings per share growth of approximately 4% in 2015 from the 2014 midpoint. As Paul indicated earlier, our earnings performance in 2015 will be affected by our ability to complete the resource diversification strategy.

We expect to execute a purchase agreement for Gila by the end of 2013 and close the transaction, meaning, purchase the asset by December 2014. In addition, we expect our Springerville Unit 1 purchase to be completed by or before the first week of January 2015. The combination of the reduction in our interest in Springerville Unit 1 and the purchase of the Gila River Unit 3 should provide incremental earnings growth through a couple of different factors.

One is, it provides lower O&M. In general, the operating cost of gas plant are below that of a coal plant. So we expect the incremental O&M related to Gila will be more than offset by a reduction in the O&M related to Springerville Unit 1. This helps in general to maintain and control our O&M growth, so it's in the 2% range as I pointed out in 2015.

Some other benefits include, with the other owners of Springerville Unit 1, they will be responsible for paying us for the usages of some of the facilities that we own up there. For example, the fuel handling facilities, and they'll have to compensate us for that and some of the other common facilities as well as for us to operate the facility that will also benefit us. We also expect the third-party owners of Springerville Unit 1 will need to use our transmission facilities to export their power and we'll pickup some benefits from that as well.

And finally, the Gila River plant, back fills the reduction capacity from the Springerville Unit 1 in 2015 and San Juan 2 in late 2017. Prior to the anticipated closer of the San Juan plant in late 2017, again that's a 170 megawatt. TEP may enter into an intermediate term wholesale contract to sell some of Gila's capacity. That we anticipate will provide incremental margins to the firm.

Other factors, moving away from specifically Gila, the other factors are going to impact 2015 include, we anticipate weather normalized retail sales growth of TEP of 0.50% to 1%. And you'll recall, as a rule of thumb, roughly 1% increase in sales worth about $0.10 a share.

We also will see some benefit from the impact of the various cost adjustment mechanisms at TEP and UNS Electric. Many of those adjusted mechanisms were put in the recent TEP or part of the TEP rate case. For example, lost fixed cost recovery mechanism, we estimate in total in 2015 to be about $8 million to $10 million. And that would be an increment of $2 million to $4 million above the level in 2014. And as I pointed earlier, we continue to see our capital lease expense decline, and in 2015 we expect our capital lease expense to decline by approximately $16 million.

Now these are some of the positives that are benefiting us, as we move into '15 from '14, but there are some offsets to that. One I did touch on, we will see some pressure on our O&M, but we expect to control that around the 2% range. Given the capital we're investing, we expect depreciation expense to increase by about $13 million.

And then lastly, given the direct debt obligations that we're going to be issuing at Tucson Electric Power Company as well as other UNS subsidiaries, the $350 million I referred to earlier, that will impact, increase our interest expense. And also given they issued some new shares and that will impact our earnings per share results to some extent as well.

And lastly, as Paul indicated, UNS Electric is expected to purchase a portion of the Gila plant, it will not be completely owned by Tucson Electric Power Company. And upon the completion of the purchase agreement for Gila Unit 3, we expect that UNS Electric would file for an accounting order to defer the cost of ownership until its next rate case. The deferral of those cost, and it's still early, in terms of our estimates, but it could be in the $8 million range on a pre-tax basis of deferred cost.

And then in conclusion, I just want to point out that in addition to the slides I've gone through, there is Slides 9 through 11 that summarize and include a lot of the key assumptions and the sensitivities for 2013 as well as 2015.

With that, I will turn it back to Paul for Q&A.

Paul Bonavia

Thanks, Kevin. Well as you can hear that's a lot of information. We hope it is of help to all of you on the call. And we're happy to take your questions.

Question-and-Answer Session

Operator

(Operator Instructions) And we'll go with our first question from the line of John Edwards from Credit Suisse.

Kevin Cole - Credit Suisse

This is Kevin Cole. I'm not sure what happened there. So thank you for the great guidance and detail. But actually, Paul, can I sort of go back to dividend comment real quick. So I guess if I use the midpoint of 2014 and a dividend variance between 60% and 70%. 70% payout, that implies a 14% to 33% dividend increased. I guess given your stronger growth rate, are you comfortable with like a one-time step-up to the midpoint of the payout ratio in 2014? Or you would you rather kind of work into over multiple years?

Paul Bonavia

Yes, and I don't want to speak to the board, that's a decision we haven't made yet. I'll tell you, we've done significant one-time step increases in the past. So that's certainly something that we'll consider. But we will also consider the longer-term earnings past that were shooting for and plugging into our 60% to 70% expectation. So that isn't a very specific answer to your question. We'll look at all of the alternatives and will try and pick the one that we think is most suitable to our earnings growth, as your question implies.

Kevin Cole - Credit Suisse

I guess, then at the end of the day it's not that much cash for it to really change your capital needs, if you went all the way to the midpoint?

Paul Bonavia

Cash is always important, but it's not that much cash. Like it is in cash, that's a driving factor as much as it is, just overall sound dividend policy.

Kevin Cole - Credit Suisse

And then can we rehash the timing of the megawatts leave and the megawatts coming? And so I guess I have it, it's effective January 1, 2015, you lose the 332 megawatts of Unit 1. Then you're purchasing the 34%, so you're getting the 137 megawatts back. That leaves you short at the beginning of 2015 around 200 megawatts. And then in like '17 you lose a 170 megawatts from San Juan and that kind of gets to your 400 megawatt shortfall for bringing in the Gila Bend. Is that the right way to think about it?

Paul Bonavia

Yes.

Kevin Cole - Credit Suisse

And then I believe, Kevin, you mention that at the end of 2017 San or Gila River, the 100 megawatts that are not been contributed to utility, they have some ability to offset some of the San Juan load in 2017. I didn't quite catch those comments?

Kevin Larson

It does. It just basically fills in as San Juan drops off in late 2017. Our interest in the Gila plant will be able to substitute for that. I pointed out in my comments that we could see on an interim basis, that we have a wholesale power sale agreement to some third party between 2015, when we purchase the asset and then let's say late 2017, when we'll need the capacity back for Tucson Electric.

Kevin Cole - Credit Suisse

I'm sorry if I asked the question twice, but so I thought the 400 megawatts that you're going contribute to day one to the utility is to cover San Juan as well not the 150 that are staying outside.

David Hutchens

We're basically buying it early, but we'll see. We've got tons of options that we're going to look at in 2015 and '16 on how we use that capacity. Just for a little bit of background, when you go into 2015 and you mentioned that we lose that 200 megawatts of Springerville, which is right on and correct, we also need another 400 megawatts of additional resources to be able to meet our peak capacity. So even if we bring all that and the entire 400 megawatts in day one, we still need to go out and buy another 200 megawatts, which we typically do on the short and intermediate terms to fill in those resource needs in 2015.

So we're buying that 400. It's basically in there and is committed for both Springerville and a little bit early purchase for San Juan, but we're going to evaluate what the wholesale market options are out there and the timing associated with that. And maybe sell a little bit of that in the shorter term out to the market and just pick up the peaking capacities that we need for our own portfolio on the shorter term market.

Kevin Cole - Credit Suisse

And then what is I guess the regulatory timing of the milestones that we should be watching for as this plant kind of comes together over the next year and a half?

David Hutchens

FERC is the only one that we have from TEP's perspective. Kevin, mentioned the accounting order that we would likely file for UNS Electric, so timing-wise FERC has a pretty quick one, I think it's 60 days, right.

Paul Bonavia

The EPA needs to act on the San Juan plant that's out there as well.

Kevin Cole - Credit Suisse

And then there is some filings late next year for Unit 1 and then when do we plan on filing for the rate deferral treatment for Gila 400 megawatts, will that be at close?

Kevin Larson

I think at or shortly after we'd be seeking our business that the deferral treatment, so it would be at about the time of the closing.

Operator

And we'll proceed with our next question to the line of Paul Fremont from Jeffries.

Paul Fremont - Jeffries

A lot of questions. Looking at that projected ACC jurisdictional rate base of $2 billion, is that just TEP or is that all of your utility?

Paul Bonavia

That's TEP.

Paul Fremont - Jeffries

So that's just TEP. Now you had initially put out a slide I think earlier this year talking about roughly $2 billion of rate base inclusive of what was then I think the entire Springville amount. The actual purchase that you're going to be doing is greater or probably by $125 million or something on that order of magnitude. Are you losing rate base somewhere else?

Kevin Larson

We haven't given the specifics of what we're going to be paying for the Gila plant. I mean generally your calculation is pretty close, but no, I don't think we're losing plants in any other locations. I mean we've always talked about the $2 billion that's kind of another super precise number, but in terms of overall estimate of where the rate base would be at that point in time and get to the end of 2015.

Paul Fremont - Jeffries

So inclusive of Gila, you expect to be at roughly $2 billion, just the TEP right?

Kevin Larson

Yes, that's correct.

Paul Fremont - Jeffries

In terms of UNS Electric, I think you mentioned all the equity infusion is going to be to TEP, so does that mean that there the purchase at UNS Electric of their 150 megawatt is done with all that?

Kevin Larson

I guess, there maybe a small portion of the $150 million of equity there referenced that UniSource would issue. As the majority would go into Tucson Electric Power Company, I said all of it will go into TEP. We will take a look at the cap structure at that point in time and make sure that UNS Electric maintains its capital structure.

One thing that we can do is we go through this process is UNS Electric often pays $10 million of dividends to the parent company. We can simply modify that dividend level, maybe it doesn't pay a dividend in the particular year, build up its equity base, so that it can then purchase this asset and still keep a good stable equity base.

Paul Fremont - Jeffries

In terms of the O&M guidance should we assume that that in the fourth quarter you're going to spend $7 million on outage costs in the fourth quarter alone for this year?

Kevin Larson

No, there shouldn't be that assumption.

Paul Fremont - Jeffries

I thought you said $4 million to date and the slide said like a $11 million for the year.

Paul Bonavia

There is a distinction. The $4 million that I reference earlier that was for the unplanned outages. And I mentioned the reason that the O&M budget is higher than we expected for 2013, is related to unplanned outages of about $4 million. And then I switched gear and talked about the differences in our 2014 budget versus the 2013 budget and much of that is been driven by higher plant maintenance outages at our power plants, and so two different categories.

Paul Fremont - Jeffries

And then, when we look at the 2% growth is off of the $288 million to $290 million, right. So it includes the $19 million in 2014 of outage expense?

Kevin Larson

Yes, it does. That's the best way to look at it. I mean the reason I say it work it off of that level was we actually anticipate at least today that our planned outage expense in 2015 may actually exceed the level in 2014. So I would just work off of as we indicated 2% increase over the $288 million we're showing.

Paul Fremont - Jeffries

But does it come down at some point then?

Kevin Larson

Yes. We would expect that we're going to start to get some relief as we get through this bulge period of funding and paying in for the planned outages. At some point, if we're funding close to $20 million of planned outages, it will start to trend back down to by over $10 million to $15 million of planned outages. So we'll pick up that benefit at that point.

Paul Fremont - Jeffries

Then the depreciation guidance I assume excludes Springerville amortization?

Kevin Larson

Yes, it does. It does exclude it.

Paul Fremont - Jeffries

Transmission margin, it looks like it was negative in the third quarter, is there some sort of a rate case or some something to fix that and what type of transmission margin do you have like built into '14?

Paul Bonavia

I think on the assumption piece and across, we indicated roughly $15 million of transmission margins on an annual basis. And I'm not aware, I'm kind of looking around others here in the room, but I don't think there was any interruption there during 2013. But anyway, I think you should assume the transmission revenues are going to be roughly $15 million per year. And I think that pointed out in some of the materials we provided.

Operator

Our next question is from the line of Maury May from Wellington Shields.

Maury May - Wellington Shields

I got a couple of questions. First of all, some clarity on your projection of debt issuance, you said $350 million of debt to be issued in the second half of 2014, which would include $250 million at TEP? My question has to do with, what about balance, the $100 million balance, some of that at the parent, some at the UNS Electric? What does that look like?

Paul Bonavia

That's correct. You divvy up the $100 million, probably $50 million at UNS Electric and $50 million at the parent company.

Maury May - Wellington Shields

So this will be the first parent level that you've had since you got rid of the converts, right?

Paul Bonavia

This maybe, I'd say a bank term facility, three years or four years type of thing or five years. It will be longer-term permanent debt. And we have had, I mean the parent company on balance under its revolver it probably carries $30 million to $40 million on average anyway. So this is stepping that up a little bit. But again, it's not going to be longer-term financing.

Maury may - Wellington Shields

And then at UNS Electric, I think when you bought that about 10 years ago, it had no generating capacity, then you bought the [ph] peaker and now you're planning on putting in some 150 megawatts of base load into UNS Electric. What are you replacing here? I guess you're replacing PPAs? Can you give us a little color on that please?

David Hutchens

This is Dave Hutchens. We're replacing short and mid-term PPAs and spot market purchases that we fill in. So there is just from a resource perspective, we have about a 450 megawatt peak load. And you're right, they had some older combustion turbines, and then we added that new one. So they have about call it 150 megawatt to round combustion turbine capacity that's run very little throughout the year. The remaining is filled in with PPAs and short-term purchases. So this would be locking that in and providing that hedge for any capacity type price increases going out in the future.

Maury may - Wellington Shields

So what you're saying -- well, I asked, the question David is, what's the net effect on rates going from PPAs to rate basing the 150 megawatt piece at Gila River?

Paul Bonavia

There is a little bit of an effect, but it's not that much. And it's obviously spread out over time. And it depends a lot on the assumptions you have in the wholesale market prices going forward, gas curve, et cetera. But I don't have the numbers off the top of my head, but that's something that we'll be filing as part of our resource plan. We did just as an on the side, get a little bit of sideways glances from the commission in our last IRP from at least from their consultants, for UNS Electric and that we were depending too much on the short-term market for serving their resources. So this is an answer in part to that and in part this is a good deal.

Maury may - Wellington Shields

When will we hear the specifics of the Gila River deal? You said it was good deal -- David, you said it was a good deal, when we're going to hear the specifics?

David Hutchens

We're still on schedule to have this papered in mid-December. And we'll be anxious to get that information out as quick as we can once we get that papered. So I'm guessing mid-December you'll know.

Operator

And we'll go with our next question to line up Brian Russo with Ladenburg Thalmann.

Brian Russo - Ladenburg Thalmann

Could you breakout the CapEx between '14 and '15?

Paul Bonavia

We're still on the process. I think what I indicated on the call or just earlier was that we estimated for to be about $500 million in each of those years. One year it's going to be a little higher and one's going to be a little bit lower. We're still working through and finalizing those numbers. So at this point, we're not giving additional detail.

Brian Russo - Ladenburg Thalmann

And these accounting orders, are you going to seek an accounting order both at UNS Electric and TEP?

Kevin Larson

No. The plan would be, if we do put the capacity in the UNSE that's the one where we'd seek the accounting order. With TEP it's offset by the lease expense that's currently build into revenues for Springerville 1. So we don't need the accounting order.

Paul Bonavia

So basically, we're just substituting the Gila expenses for the current cost that we have of 100% interest of Springerville Unit 1. So it's just a substitution of costs. We're kind of in the same spot before and after.

Brian Russo - Ladenburg Thalmann

UNS Electric has to file a rate case for the accounting order, so I believe that's how it work with APS, meaning the accounting order in deferral to four corners acquisition cost, we're kind of included in that rate case settlement.

Paul Bonavia

No. That's not required that we file a rate case, we can file for an accounting order completely independent of that process and that's always will be done.

Brian Russo - Ladenburg Thalmann

The LFCR sub revenue recovery, I mean, you sound pretty good growth in '14 over '13 and again '15 over '14, but that's all contingent on ACC review and approval, correct?

Paul Bonavia

Yes. It is.

Brian Russo - Ladenburg Thalmann

And you've given kind of a fairly wide range of your timing of equity needs, and I'm just curious could you be a little bit more specific or is there any like CapEx or acquisition figures that the timing of the equity is more closely aligned with?

Kevin Larson

I gave a pretty wide or basically a full year period that we'll be looking at between April of 2014 and probably through the first half of 2015. And much of that will be dependent upon just what the market conditions are. As we pointed out earlier, we're going to need a lot of the funding once we close on Gila. We anticipate to close on Gila in December of 2014, and then moving into 2015, that's when we'll purchase our interest in Springerville Unit 1. So we'll be focused on just making sure that we've got sufficient resources to make those purchases. And will evaluate the equity markets over time to figure out the appropriate time to enter the market.

Brian Russo - Ladenburg Thalmann

And remind us, when is the informational filing on Springerville 1 lease rate expected?

Kevin Larson

July of 2014.

Brian Russo - Ladenburg Thalmann

I imagine that your '15 guidance assumes flat rates?

Kevin Larson

Yes, it does.

Brian Russo - Ladenburg Thalmann

And then just curious in your service territory, with impact of energy efficiency et cetera, the APS reported a 3Q '13 whether normalized decline in load and I think they may have cited usage partners. So I'm just curious, what are you seeing like in the seasonal peek demand third quarter or are you seeing much more conservation than you see in the shoulder periods?

David Hutchens

We're seeing in a little bit better load shape. We're seeing a little less growth on the peak than we are on overall energy growth. But other than that I don't really have any real details on exactly whether we see more of it out. You see that's when people focus on at the most is in the summer, not only the rate differential impact, but obviously the usage differential than they do in the summer and the winter. I mean our winter builds are pretty darn low, so if you looked at it just from anecdotally like that you would see most of that energy efficiency affect in the third quarter.

Operator

We do have another follow-up question from the line of John Edwards with Credit Suisse.

Kevin Cole - Credit Suisse

This is Kevin, again. Actually one follow-up question, I had in my notes that you said that there is $8 million of expected Gila deferral of $0.12. Is that baked into your 2015 guidance or is that upside or downside?

Paul Bonavia

That is factored into it. We do assume that we're going to get the accounting order there as precedent. We expect the ACC to provide us that deferral accounting.

Kevin Cole - Credit Suisse

And then just one small question, that on the $2 billion of TEP rate base, does that include transmission or wholesale?

Kevin Larson

No, that's ACC jurisdictional assets.

Kevin Cole - Credit Suisse

What would transmission and wholesale be in '15?

Kevin Larson

I would just spend around $500 million.

Kevin Cole - Credit Suisse

And that's largely translate $450 million of transmission?

Kevin Larson

Yes, that's high voltage transmission in one period.

Cole - Credit Suisse

And so it's $500 million per transition only?

Kevin Larson

Yes, the $500 million for FERC based transmission assets.

Kevin Cole - Credit Suisse

And then you said for $138 million for wholesale.

Kevin Larson

I mean at the 138kV and above in terms of the sizable transmission.

Kevin Cole - Credit Suisse

And then with wholesale, I guess pre-Gila, what do you think that would be?

Kevin Larson

You're just asking what's the portion of our generation assets, that goes to FERC jurisdiction. And it was in recent rate case is $70 million.

Operator

And Mr. Bonavia, we have no further question at the time. I will now turn the call back to you for any closing remarks.

Paul Bonavia

Well, thank you again all of you joining us. We know that' a lot of information and we look forward to seeing many of you next week. Safe travels.

Operator

Thank you, very much. And Ladies and gentlemen, this concludes the conference call for today. We thank you for your participation, as please disconnect your lines. Have a great day everyone.

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