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Executives

Mark M. Kane - Director of Investor Relations

Sandra W. Callahan - Chief Financial Officer, Senior Vice President of Finance & Accounting and Chief Accounting Officer

John B. Ramil - Chief Executive Officer, President, Director and Member of Finance Committee

Analysts

Ashar Khan

Greg Gordon - ISI Group Inc., Research Division

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Paul Patterson - Glenrock Associates LLC

Andrew Bischof - Morningstar Inc., Research Division

Andrew M. Weisel - Macquarie Research

Chris Shelton

James D. von Riesemann - UBS Investment Bank, Research Division

Timothy M. Winter - Gabelli & Company, Inc.

TECO Energy (TE) Q4 2012 Earnings Call February 5, 2013 9:00 AM ET

Operator

Good morning. My name is Keisha, and I will be your conference operator today. At this time, I would like to welcome everyone to the TECO Energy's Fourth Quarter Results and 2013 Outlook Conference Call. [Operator Instructions] Mr. Mark Kane, you may begin your conference, sir.

Mark M. Kane

Thank you, Keisha. Good morning everyone, and welcome to our conference call this morning. Our earnings, along with unaudited financial statements, were released and filed with the SEC earlier this morning.

This presentation is being webcast and our earnings release, financial statements and slides for this presentation are available on our website at tecoenergy.com. The presentation will be available for replay through the website approximately 2 hours after the conclusion of our presentation this morning, and we expect it to be available for 30 days.

In the course of our remarks today, we will be making forward-looking statements about our plans and expectations for 2013, our Polk conversion project and Tampa Electric's base rate proceeding.

There are a number of factors that could cause actual results to differ materially from those that we'll discuss today. For a more complete discussion of these factors, we refer you to the risk factor discussion in our Annual Report on Form 10-K for the period ended December 31, 2011.

The host for our call today is Sandy Callahan, TECO Energy's Chief Financial Officer. Also with us today is John Ramil, TECO Energy's Chief Executive Officer, to assist in answering your questions.

Now I'll turn it over to Sandy.

Sandra W. Callahan

Thank you, Mark. Good morning, everyone, and thank you for joining us. Today, I'll cover our fourth quarter and full year results, what we're seeing in the local and state economies, our 2013 guidance and the test year notification that Tampa Electric filed with the Florida Commission yesterday.

In the fourth quarter, net income from continuing operations was $45.6 million or $0.21 a share, compared with $47.3 million or $0.22 in 2011. The small net impact of discontinued operations in the quarter includes results for the San José power station through the closing date of the sale and adjustments to the loss on sale and tax charges. And I'll show you the detail on a later slide.

On a full year basis, net income from continuing operations in 2012 was $246 million or $1.14 per share, compared with $250.8 million or $1.17 in 2011. The most significant factor impacting the year-over-year comparison was the effect of weather and customer usage on electric sales.

Here are the details on the discontinued Guatemalan operations. The San José power station was offline for a scheduled turbine overhaul for most of the fourth quarter through the closing date. Note that under the full year, the operating results of $18.2 million do reflect the Guatemalan operations from January 1 until their sale, although we didn't classify them as discontinued operations until the third quarter, at which time we recast our guidance for the full year accordingly. The final loss on sale and the charge associated with the tax credits are somewhat less than we expected at the time we announced the sale.

I'll touch briefly on the 2012 business drivers that were covered in detail in the earnings release. Tampa Electric reported slightly lower net income in the quarter despite having good customer growth and slightly better weather than last year.

Since customer growth began to recover at the end of 2009, it has been on a solid trend up and, for the third and fourth quarters of this year, reached 1.4%, approaching what we expect to be the new normal for customer growth.

Retail net energy for load in the fourth quarter was 3.5% better than last year, and base revenue rose $5 million. For both the quarter and full year, Tampa Electric had lower interest expense, higher depreciation due to normal additions to facilities and higher operations and maintenance expense. Tampa Electric's net income for the full year was lower than 2011 and reflected customer growth of 1.2%.

Although retail net energy sales were slightly higher than last year, base revenues were $6 million lower, the result of higher energy sales to the lower-margin interruptible phosphate segment but lower sales to residential customers.

The residential volumes reflected a mild winter and a rainy summer, as well as changes in usage pattern. The normal degree days for the full year period weren't particularly helpful because they represented higher cooling degree days in the mild shoulder month, offsetting lower degree days in the winter and summer. Cooling degree days in the mild spring and fall shoulder months just don't result in higher energy sales the way hot summers and cold winters do.

Peoples Gas reported fourth quarter results about in line with last year and customer growth that reached 1.4%. Despite another mild start to the winter, we saw therm sales increase in every retail segment, residential, commercial and industrial, as previously vacant residential housing was occupied and the Florida economy continued to improve. Peoples also had a higher O&M in the quarter compared with 2011. Full year results at Peoples Gas rose, driven by customer growth and higher sales to commercial and industrial customers. And for the year, O&M expenses were lower than 2011.

TECO Coal achieved better margins on coal sales this quarter, but volumes were substantially lower than last year. The average selling price for the quarter rose to $96 per ton, reflecting met coal prices locked in when the market was stronger and higher average steam coal prices following the expiration of a below-market contract at the end of last year. The all-in cost of production in the quarter was $84 per ton, which reflects TECO Coal's aggressive actions to manage cost.

Full year results, only slightly behind 2011 despite significantly lower volumes. Strong margins in 2012 reflected an average selling price for the year of more than $95 per ton and a total all-in cost of production of $85 a ton. This cost, only slightly above the middle of our cost guidance range, included spreading fixed costs over fewer tons, as well as costs associated with idling facilities in both the first and fourth quarters.

All of the local and state economic trends we've been showing you over time continue to be positive. In December, the unemployment rate in Hillsborough County, which is Tampa Electric's primary service area, dropped to 7.6%, which is below the state and national levels for the first time since December 2006.

In 2012, the local area economy added 21,000 jobs, primarily in professional and business services, education and health services and hospitality services. The housing market also continued to strengthen, with more than 4,400 new single-family building permits issued in Tampa Electric's service area last year. Existing home resales remained strong and have brought the inventory down to a new low of just over 3 months. And resale prices posted a 6.8% year-over-year increase according to the most resent Case-Shiller report.

Growth in taxable sales has also continued its trend, with a 4.7% year-over-year increase for the most recent 12-month period reported, which was October 2012. We're encouraged by the trends that we've seen in the state and local economies and housing markets, and our forecast for 2013 assumes that these continue to improve at a modest pace. You can see these trends visually in some graphs that we've included in the appendix to today's presentation.

We are initiating our 2013 earnings per share guidance in a range between $0.90 and $1. The major drivers of the 2013 guidance are shown here. We anticipate that Tampa Electric will earn below the bottom of its allowed ROE range of 10.25% to 12.25%, that Peoples Gas will earn above the middle of its allowed ROE range of 9.75% to 11.75% and that TECO Coal has positioned itself to achieve net income in the neighborhood of $12 million in this very weak coal market. We declared a $0.22 per share quarterly dividend, $0.88 on an annual basis, unchanged from 2012.

We are maintaining the dividend this year in consideration of an earnings year characterized by Tampa Electric's need for rate release and the current weak coal market. The middle of our guidance range would suggest a payout ratio of more than 90%, which is well above our target payout range of 60% to 70%. Our tax position, though, results in cash coverage of the dividend that's much stronger. And with rate release at Tampa Electric and an outlook for improved earnings in 2014, we look forward to being able to resume our pattern of steady ratable dividend growth next year.

At Tampa Electric, we expect customer growth to reflect the trends that we've experienced this year. Consistent with the longer-term forecast we've described before, we anticipate that retail sales growth will be about 2.5% below the expected customer growth.

In the residential and commercial customer classes, that expectation reflects the impact of new lighting efficiency standards and increased appliance efficiencies. For residential customers, it also reflects smaller and more energy-efficient houses and more multifamily units.

Sales to phosphate customers were strong in 2012, reflecting outages on some of their self-generating units early in the year and the relocation of mining equipment to Tampa Electric's system, so we expect reduced sales to this sector in 2013 as self generation at those customers comes back on. Tampa Electric will also experience earnings pressure from higher O&M and depreciation in 2013.

Peoples Gas expects to benefit from continued customer growth, more compressed natural gas vehicle conversions and from industrial customers converting from petroleum or propane to natural gas.

You may have seen that yesterday, Tampa Electric notified the Florida Public Service Commission that we will be filing for a base rate increase in April of this year. We will be filing a 2014 projected test year for new rates effective in early January '14. We haven't finalized the calculations, but currently estimate the base rate request at $135 million. We think that our current allowed ROE range with a midpoint of 11.25% remains appropriate with the major generating unit construction programs getting started.

Tampa Electric has the second lowest rates among the IOUs in Florida, and we expect to maintain that position even with higher base rates in 2014.

As you know, we had hoped to avoid seeking rate relief for as long as possible, and we've done everything we could to try to achieve that outcome. But since our last base rates were set, Tampa Electric has invested more than $700 million in assets to safely and reliably serve customers, and revenue growth just hasn't been there to support the required growth in rate base and the associated depreciation. In response, we have aggressively managed O&M, and very successfully. In 2012, Tampa Electric's O&M was essentially the same level as 2007. That just isn't sustainable, and we saw that start to pressure us in 2012.

TECO Coal expects 2013 sales to be in a range between 5.2 million tons and 5.7 million tons. All of the 2.7 million tons of steam coal that are included in that total is contracted at prices ranging from $75 to $82 per ton. There are 2.2 million tons of met coal contracted and priced, but they are at prices well below 2012 levels. All of the unsold tons are specialty coal, primarily a mix of our high-vol A and B products. We do expect to be able to sell these tons later this year.

The average selling price for all 2013 tons is expected to be about $86 per ton, and the average cost is expected to be in a range between $81 and $85 per ton. This average cost is actually below 2012 cost levels, although we will be spreading fixed costs over fewer tons. This reflects the significant efforts at TECO Coal to position the business for the lower volumes and reduce both overhead and mining costs, including lower head count, fewer shifts, less overtime and the temporary idling of higher-cost sections. At the middle of the volume and cost ranges, TECO Coal could produce about $12 million of net income this year.

Now let me update you on our plans to convert Polk units 2 to 5 to combined cycle service. This is a $700 million project, including about $100 million of AFUDC, which will start ramping up in 2013 and peak in 2016. The total cost of the project includes about $150 million for transmission system improvements to support the increased output from the plant. The project, which will support customer growth and, importantly, replace expiring purchase power agreements, is scheduled to go into service in January 2017.

We received a determination of need from the FPSC in a rare bench decision in December last year. We have applied for the site certification from the state of Florida, which we expect in the fourth quarter of this year.

I want to provide some color on our current outlook for parent cash. We effectively have a timing mismatch with our commitment to support Tampa Electric's capital programs and the realization of cash tax benefits at the parent.

It might help to first recap how cash flows between parent and subsidiary within our consolidated entity. Inflows to parent include dividends of 100% of subsidiary net income and income tax payments from each subsidiary. They're calculated on a standalone basis. Cash outflows from parent include cash contributions to subsidiaries in the form of equity infusions to support investment in those businesses and payment of income taxes due on our consolidated tax return.

So the source of the timing mismatch in 2013 and 2014 is this. Tampa Electric's peak spending on the Polk conversion will occur in 2014 and 2015. In 2013 and '14, the parent company expects to make cash contributions of equity to Tampa Electric as construction peaks, estimated at $220 million to $250 million.

There are 2 significant tax items that will affect 2013 and 2014: the extension of bonus depreciation under the fiscal cliff legislation in January and the expected technical guidance on repair deductions for generation activity. The resulting deductions in 2013 and '14, primarily at Tampa Electric, will lower the utilities payments for federal income taxes, and thus will benefit utility operating cash by an estimated $120 million to $150 million over those 2 years. This, of course, represents a reduction in cash taxes remitted to the parent level.

We've modified our current outlook for parent cash to reflect the revised cash flow timing. And as a result, a majority of the proceeds from the sale of TECO Guatemala will support our planned investment in Tampa Electric in 2013 and 2014. We did use proceeds to reduce debt $35 million, which included the San José project debt paid off at closing.

Beginning in 2013, we plan to repurchase shares to offset shares issued under compensation programs and may repurchase additional amounts as opportunities arise. This might amount, in total over the next several years, to as much as $50 million.

This is an interesting slide, and it shows graphically the effects of bonus depreciation on our NOL utilization. The original value of the deferred tax asset that was associated with the net operating losses that resulted from our exit of merchant power was $850 million. Now in the first few years, we were able to apply some of the net operating losses against taxable income and realize over $300 million of that tax value. But then in 2008, bonus depreciation kicked in. And in 2009, the repair rigs came out. So from 2008 through 2012, you can see the line flatten here. We've only realized about $70 million of tax value over that full 5-year period.

Now the good news, of course, is that the bonus depreciation and repair deductions have extended the period of time that the NOL carryforwards will be available to us. The remaining value of the deferred tax asset associated with the NOLs is about $465 million as of the end of 2012. While we expect to fully realize the cash benefits, we now expect that most of that will occur in the 2015 to 2017 period.

I'll close with our upcoming investor communication activity. We will file our 10-K by the required March 1 date. But as typically we do, we're targeting to file a few days ahead of the file date. We'll be at the UBS Conference in Dallas the first week of March and at the Morgan Stanley Conference in New York later that same week. The past several years, we've been in Europe in March. But this year, we're actually targeting early fall for that investor trip.

And now I will turn it over to the operator to open the lines for your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Ashar Khan with Visium.

Ashar Khan

Can I just -- based on what you provided, if I'm doing my math right, we lose like about $0.17 in the earnings at TECO Coal. And then, I guess, the midpoint of the range is $0.95. Is it fair to assume that you're losing another $0.05 at the electric company, $12 million to $13 million?

John B. Ramil

Ashar, this is John Ramil. I think you're right on, on coal. We're going from about $50 million net income to the guidance of about $12 million. And then we'll be down a little bit at the electric company. But the guidance range is $0.90 to $1, and the middle is $0.95.

Ashar Khan

Okay, okay. And can you, John, can you just help us, just so we have -- what are we -- are you expecting in '13 at the electric company?

John B. Ramil

Well, in '13, we're expecting the things that Sandy talked about in her presentation and in her slides. And we did earn right near the bottom of the ROE range at the electric company in '12. I think the number was right at about 10.4%, and expect to be a little bit south of that as we move into 2013.

Ashar Khan

Okay. And can you remind us how much is 100 basis points equal into -- in cents per share at the electric company?

Sandra W. Callahan

Yes. 100 basis points, is that what you're asking?

Ashar Khan

That's correct.

Sandra W. Callahan

Yes, 100 basis points of ROE is the equivalent of about $25 million in revenue requirements. And so that's, obviously, a pretax number.

Ashar Khan

Okay, so about $0.08 a share or something?

John B. Ramil

A little less than that, Ashar.

Sandra W. Callahan

[indiscernible]

Operator

Your next question comes from the line of Greg Gordon with ISI Group.

Greg Gordon - ISI Group Inc., Research Division

On the guidance on sources and uses of cash, can you remind us what the total proceeds are from Guatemala? I think you had said before that you'd use half of it to retire debt and half of it to buy back stock. So can you just go through what the guidance was before for total proceeds and uses and now how that's changed? You did explain why it's changed, but can you just review those numbers?

Sandra W. Callahan

Sure. The gross proceeds were $227.5 million. And so after expenses and after paying off the debt at San José, it was about $195 million, roughly. Our expectation originally was that we would have approximately -- we would use that in a balanced fashion to reduce debt, including the debt that we retired at the closing that represented San José and share repurchase. Our expectation now is that -- we've already reduced that by $35 million, so we did deploy proceeds in that fashion. In terms of share repurchase, we have reduced our expectation there. And as I said, it's not likely that, that will exceed $50 million over the next several years, the combination of both buying back shares to effectively offset shares that are typically issued on an annual basis to support compensation programs and, perhaps, some opportunistic share repurchases. The balance of that, really, we would be using to support Tampa Electric's capital program over the next several years.

Greg Gordon - ISI Group Inc., Research Division

Okay, I got it. But the other side of this is that the value of the parent package [ph] position has been preserved for a longer period of time because you got the bonus depreciation which you hadn't expected, is that correct?

Sandra W. Callahan

That's absolutely correct. This really is a timing question. And I would emphasize that the bonus depreciation and repair deduction is a positive for the company, because it has increased cash flows at Tampa Electric. That has been helpful for the business in terms of supporting its capital program. And it has extended the period of time that the parent company will be able to benefit from the future applications of those net operating losses to reduce taxable income.

John B. Ramil

Greg, I would add -- this is John. I would add that, as we think about deploying capital, the first place we want to put it is into the utility business when we have the opportunity to make those returns. And with the extension of bonus depreciation and all of the things that Sandy described, plus as we move further into the Polk expansion project, the very, very positive supported lead we got from the commission and the need to go ahead and invest in that plant more quickly than we had earlier anticipated, the primary first use of cash would be to invest in the electric company. And that's what we're doing. And the stock repurchase will move to an opportunity purchase.

Greg Gordon - ISI Group Inc., Research Division

All right, one final question, guys. I understand that this year it looks like cash sources and uses and earnings power kind of get squeezed a little bit. But with the longer-term cash flow file looking the way it does, why sort of abstain from a dividend increase this year? It's a very -- relatively small amount of dollars in the scheme of things.

John B. Ramil

It is a small amount of dollars, Greg. And cash '13, '14 is going to be just fine, as you pointed out. Longer-term, very strong with our NOL position. The management team just thought that as we slug through 2013, earnings were kind of tagged, the payout ratio was very high and it wasn't the time to raise the dividend, and the board agreed. But I'll quickly add that we look forward to getting back to our normal pattern in '14 and move back to consider raising the dividend.

Operator

Your next question comes from line of Jonathan Arnold with Deutsche Bank.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Just on the dividend question, when you think about raising it in 2014, can you give us a sense of what you're thinking about in terms of target coverage ratios, and maybe whether the utility coverage is what we should look at? Obviously, Guatemala's not in the mix anymore, so just some color on how you're going to think about that going forward?

John B. Ramil

So Jonathan, our broad policy in guidance is a 60% to 70% payout ratio of earnings. And our expectation is, with the things that we expect to transpire during 2013 and be in effect in '14, we'll be back in the position to consider dividend increases that is in and around that policy. If you look historically, we've been 3% to 4% raise in the dividend, and that's where we'd like to get back to.

Operator

Your next question comes from line of Keith Conalege [ph] with BGC.

Unknown Analyst

Just to beat on the dividend one more time. And obviously, you can't be pinned down too much on this. But historically, a lot of companies have been in a kind of delicate position, shall I say, when they've had a rate case and a hopefully rate increase. So supposing this rate case ran and -- can you give us an idea when you'd expect the rate increase to go into effect? And just any broad sense of, let's say, political sensitivities to raising the dividend right after a rate increase?

John B. Ramil

Well, first of all, the timing on the rate case as we filed the test letter, that kicks in timing such that in April we will make our full filing on the case. We'd expect hearings late this summer and rates to go into effect in early of 2014. And that's the prescribed time frame in the process. The dividend decision was driven by the factors that I discussed and Sandy discussed earlier, and that was the decision.

Unknown Analyst

I'm thinking about, John, with respect to the potential for raising the dividend in '14 and beyond, can you give us a sense of would we be looking at kind of basically a year from now that we might see a dividend increase considered, or would it potentially be later in the year? Is...

John B. Ramil

Got you. Now our timeline for considering a raise in the dividend is typically early in the year when we give guidance for the year.

Mark M. Kane

About 2 years ago, Keith [ph], we shifted that timing. We used to do it In May. But in 2011, we've moved that timing up to, as John just described, at the time that we provide guidance.

Unknown Analyst

Great. And one other area. Could you give us a little more color on the cost pressures at the utility? Sandy, you mentioned O&M being flat for essentially 5 years, and that's not a sustainable position forever, obviously. And maybe a view towards other costs, now the depreciation has gone up?

John B. Ramil

Yes, Keith. Our team has done a super job of controlling those costs. They're most within their ability to control, the pure operating costs. In fact, as Sandy noted, we operated in 2012 at the same O&M levels that we operated at 2007. So we've done a good job. The ones that are more difficult, more out of our control have been the most frustrating, those associated with the cost of depreciation, which is tied to the investments that we've had to make to keep up with the modest growth we've had with reliability needs, with replacing outdated equipment and meeting new standards, including cybersecurity standards, as well as those benefit costs like pension that are driven in large part by the discount rates that we've achieved.

Operator

Your next question comes from the line of Ali Agha with SunTrust.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

John, can you give us a little more insight into your thinking on the coal outlook going a little more forward? Are you looking at 2013 really as a trough year? I mean, should we assume things kind of float along for another year or 2 before improving? Can you give us some help on seeing how coal goes, let's say, '14 and even beyond that?

John B. Ramil

Sure, Ali. We view, for all of TECO Energy, 2013 being a trough year with the regulatory activity at the electric company, as well as the soft coal market. We are monitoring the market. We need the same things that you're reading, talking to our customers. Census, the steam market will remain relatively soft, though we think there will be needs for utilities to buy steam coal in '14. And there are signs of the met markets picking up. We do have steel producers still operating in the 70% to 75% range. We know they've taken down inventories. We're seeing appliances, car sales, home sales pick up, all of which drive steel, so the indicators are positive there. We believe there's a little bit of activity in Europe. And there might be the need, as they get past the first quarter, for purchases there, so we're seeing signs. Unlike moving from '12 into '13, where it was all very, very soft, we're starting to see some signs of light picking up on the met market side. So our expectations are that the market will get better as we move from '13 to '14 in the coal business. Also, let me remind everybody that we do have about 1.2 million tons -- right at 1.2 million tons of steam contracted for 2014 that was done in a better market. That price is north of $80 a ton.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And question, looking at '14 and going back to the dividend outlook, et cetera, I mean, is it fair to say that -- I mean, is it all the regulatory activity of the utility that's giving you the confidence on building growth going forward? Or if I'm hearing you right, we should assume that coal in '14 should be somewhat better than '13? Is that a fair assessment?

John B. Ramil

Knowing what we know about the market right now, that's where we would lean, that '14 is going to better than '13 in the coal business. And as we look at the -- Peoples Gas continues strong. We expect that to keep growing. And we look at our regulatory activity at Tampa Electric. We've got about 3.8 billion in rate base there. Before we add the expansion at Polk, we're growing rate base by about $100 million a year. So when we get our rates reset, capture the current sales level and then start on top of that, start adding the earnings power that the addition of Polk will have, we see that growth, that's where the growth driver is coming from.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Last question, John. I know -- I think it was even in the last -- I think it was the last earnings slide, or maybe even the EEI deck, you had given us some rate base numbers for both Tampa Electric and Peoples Gas. Are those still good numbers that we should be thinking about looking forward?

John B. Ramil

Yes, I think what you're referring to is the chart we showed you from now until 2017, driven in large part by the Polk expansion, about a 5% average per year growth in rate base at Tampa Electric. And at least that much, maybe a little bit more than that at Peoples Gas. Those are still good.

Operator

Your next question comes from line of Paul Ridzon with Keybanc.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

You're now saying that $50 million buyback versus the prior was at 95 or so?

Sandra W. Callahan

We didn't specify an amount before, Paul. We just said that our expectation was that we would use the proceeds in a fairly balanced fashion between debt and equity. And we're estimating now that between buying back shares to offset shares issued under compensation programs and potentially taking advantage of other opportunities, that over the next several years that amount in total might approach $50 million.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Should we think about a flattish share count over the next several years?

Sandra W. Callahan

Yes. Flat to down.

Paul Patterson - Glenrock Associates LLC

Okay, down if you're opportunistic, okay.

Sandra W. Callahan

Correct. Because it has, as you know, crept up a little bit every year from issuances under the compensation programs. And we're basically going to make that go away.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

And your dividend payout ratio is 60% to 70%. Is that total earnings? Or I mean, how do you -- obviously, coal can be pretty volatile. How do you think about that when you establish a policy?

Sandra W. Callahan

I mean, we do look at consolidated earnings, but we also look at how much of the dividend is the utility's supporting.

Operator

Your next question comes from line of Andy Bischof with Morningstar.

Andrew Bischof - Morningstar Inc., Research Division

In regards to the coal business, I apologize if I missed this, but can you explain how you plan to maintain per unit ton costs? And what leverage you might have to get to the lower end of the $81 to $85 range?

John B. Ramil

We have done a lot of work in the coal business, reducing our costs, and it's a combination, Andy, of several things, from rethinking where we're mining to rethinking how we schedule our shifts to also just reducing the amount of resources that we have in that business to lower our costs, and that's been successful. The counter to that has been lower production, which spreads our fixed costs over fewer tons. But our folks have done a good job of offsetting that, so that -- we've been able to offset. If you just look at last year, we estimate that the -- just the reduced tonnage added about $4 a ton fixed costs to our costs, but our folks offset a good bit of that with the work they've done. We've done that, have made good achievements there. Obviously, we'd like to operate lower in the range than higher in the range, and that's everybody's goal, to increase the margin as much as we can. We've also done it in a way that is reversible. So as the market comes back, we haven't left any good quality tons that we can't get at. And we believe we've also positioned ourselves where we would be able to extract higher margins in the future than we would have without the work we've done to reduce costs.

Operator

Your next question comes from line of Andrew Weisel with Macquarie Capital.

Andrew M. Weisel - Macquarie Research

I appreciate all the detail on the strategy-type question. I'd love to just pin you down on a few modeling ones now. Did I hear you correctly that the weather-adjusted low growth you're expecting next year would be about half of the 1.2% customer growth forecast?

John B. Ramil

No. We said about 0.5% below the customer growth, not half of.

Andrew M. Weisel - Macquarie Research

Okay, so about 0.7%?

John B. Ramil

If that's what the math says, yes.

Andrew M. Weisel - Macquarie Research

Okay. How about -- I know it's a little early. You haven't actually filed the rate case yet. But you talked in the letter of intent about lower-than-expected growth in demand. Any sense as to what the longer-term outlook might look like in '14 and beyond?

John B. Ramil

Longer-term, our forecast that we filed last fall with the Polk proceeding -- actually, last summer, was long-term customer growth of about 1.3% and the same energy sales growth, about 0.5% below that.

Andrew M. Weisel - Macquarie Research

Got it. Okay, very good. And then the O&M increases, you talked about a step up in '13. Can you quantify that, and then the same question about what the longer-term outlook might look like?

John B. Ramil

We have not quantified that for '13. Our objective is to keep those things that we can control as low as possible. And a key factor that we've looked at as we've put together our plans to file a rate case is where we stand on our O&M with respect to the Florida Commission benchmark. And we remain in good shape with respect to that.

Andrew M. Weisel - Macquarie Research

And the benchmark is what?

John B. Ramil

Growth and inflation.

Mark M. Kane

Right. We'd add adjustments for new generation capacity.

Andrew M. Weisel - Macquarie Research

Okay, great. And then lastly, for parent expenses in '13, should we think of that as being in the same ballpark as in '12?

John B. Ramil

The interest.

Sandra W. Callahan

Slightly less, because we have -- we've repaid a small amount of parent debt at the end of 2012. But generally, fairly consistent.

Operator

Your next question comes from the line of Julie Frasier [ph] with Millennium.

Chris Shelton

Chris Shelton. A couple of follow-ups. I guess, first on -- just on the utility. The Bonus Depreciation, Sandy, you outlined the cash flow impacts, but does this have any impact on the rate base as well?

Sandra W. Callahan

It doesn't specifically affect the rate base. That isn't how Florida regulation deals with it. Deferred taxes in Florida are considered a part of the overall capital structure. And so it has been beneficial in terms of customer prices, because that capital carries no cost.

Chris Shelton

Okay, understood. And then we may wait for the rate case on this, but do you have a rate base number you can share with us for '14 at this point?

Sandra W. Callahan

No, we don't. $3.8 billion was the amount at the end of September, and so you can think about some of the growth components that John [indiscernible], or we might be.

Chris Shelton

And so you guys had, had a slide, I forgot which call it was, that had the rate base grow through the Polk construct, I guess, is that -- can we largely use that -- continue to use that going forward, I guess?

Sandra W. Callahan

Yes.

John B. Ramil

We used that at EEI, Chris, last year.

Chris Shelton

That was at EEI, yes, okay. And then just on the coal business, I guess, John, in the release, you had mentioned $12 million of -- $12 million would be the net income for 2013. I just wanted to make sure it was apples-to-apples. Does that include that allocated interest that you guys allocated from a parent, I guess?

John B. Ramil

Yes, it does.

Sandra W. Callahan

And the all-in costs of production range that we provide have that baked into it. It truly has every cost that is associated with that business.

Chris Shelton

The $12 million net income is what you're saying?

Sandra W. Callahan

Yes, our...

John B. Ramil

Yes, the cost range of $81 to $85 a ton, it has everything in there, including the...

Sandra W. Callahan

All the G&A-allocated interest.

Chris Shelton

Okay, so it's a fully-loaded cost number?

John B. Ramil

Absolutely.

Mark M. Kane

Yes, that gives you a pretax margin, Chris. You just apply income taxes at 25%.

Chris Shelton

Got it. And then is there any way you can share what -- how many -- in the 2013 tons that are sold, how many of those tons are PCI tons versus the higher quality, I guess?

Mark M. Kane

There are PCI tons in the mix, Chris. It's not a big number. I don't have that at my fingertips, but there are PCI tons in there. And to be honest, that is probably our -- in the met sector, that's our lowest-priced product right now.

Chris Shelton

Right. Okay, but is it -- if you look at the kind of specialty tons, is it 50-50 like it was before? Or is it more geared towards the...

Mark M. Kane

It's less than that, Chris. I mean, it's -- all of these specialty tons, there's always 300,000 tons of stoker in the mix, ballpark. What's remaining is A and B, which always -- typically splits 50-50. In our typical A and B, production runs 1.7 million tons, 1.8 million tons a year, typically, and then the remainder would be PCI.

Chris Shelton

Got it. And then final question, and then I'm done. The -- of the unsold tons that are high-vol A and B, do we know what -- or can you share with us what the assumed price you're using? Is it the current market price or something different?

Mark M. Kane

It's what we would expect to realize in the current market conditions.

Operator

[Operator Instructions] Your next question comes from the line of Jim von Riesemann with UBS.

James D. von Riesemann - UBS Investment Bank, Research Division

Can you just talk a little bit or elaborate on the factors that are driving the expected 7% ROE at Tampa? Basically, can you parse what might be pensions, what might be depreciation, what might just be general O&M, maybe in large buckets?

John B. Ramil

Where did you get 7%?

James D. von Riesemann - UBS Investment Bank, Research Division

From your 8-K filings yesterday.

John B. Ramil

Oh, for '14?

James D. von Riesemann - UBS Investment Bank, Research Division

'14.

John B. Ramil

Okay.

Sandra W. Callahan

The answer is not in specific detail, because we'll -- that will all be a part of the filing that we make when all of that is specifically detailed out. But in general, depreciation has increased pretty steadily every single year, and it will continue to do that through 2014. Rate base has grown, and the equity that has and will go into Tampa Electric to support that growth has been increasing. And O&M as well going up, and that's really a function of a broad array of things, including benefit costs that have been discount rate-driven. And so all total, it's having the effect of pushing the earned ROE down into that 7% area.

James D. von Riesemann - UBS Investment Bank, Research Division

Okay. I didn't catch -- maybe you didn't say it, but I didn't catch where you said your discount rate was going on the pension?

Sandra W. Callahan

Yes, we used -- just to go from '12 to '13, we used 5.3% in '12, I think. And it's down about 0.5%. And -- or maybe it was -- it's down about 50 basis points.

John B. Ramil

I'll follow up with you on that specific.

James D. von Riesemann - UBS Investment Bank, Research Division

Okay. Question on -- you guys have done a great job in containing costs over the years, but how should we think, prospectively, about maybe the structural lag between earned and allowed ROEs going forward? Is there going to be a delta between the 2?

John B. Ramil

I don't think we can give you anything specific there, Jim. When we're coming out of a regulatory procedure like we did last time, our objective is to earn that allowed ROE. And we'll continue to do everything we can to do that, moving forward. Our objective would be to eliminate the lag, at least from the things we can control.

James D. von Riesemann - UBS Investment Bank, Research Division

Okay. And then the last question, if you don't mind, is on Polk. How do you plan to finance the Polk station, prospectively?

Sandra W. Callahan

Actually, there will be equity contributions from the parent. And as I mentioned, in '13 and '14, we anticipate that, that will be between $220 million and $250 million. And the incremental borrowings at Tampa Electric, such that their capital structure is maintained at the level that we committed to, which is 54% equity and 46% debt.

John B. Ramil

Yes, just a reminder, Jim, as we get to a more normal situation without bonus depreciation and repair activity, the parent's generating about $200 million a year in cash and with our NOL position.

James D. von Riesemann - UBS Investment Bank, Research Division

So you don't -- so given the tax position, you're not going to have to issue any equity going forward for the Polk station, is what you're saying?

John B. Ramil

Yes, that's the plan.

Operator

Your next question comes from the line of Tim Winter with Gabelli & Company.

Timothy M. Winter - Gabelli & Company, Inc.

I was wondering if you guys had given update on the development of that 65 million ton metallurgical coal find, I think, back from late '11, how much you're spending there, maybe an update on the -- or color on the quality of coal, what have you?

John B. Ramil

Yes, you bet. We are not spending anything, at least anything measurable, on that project. You may remember that our plan was to establish reserves, which we did, and then to obtain the state permits, which are -- all the permits we need to develop those reserves in 2012, and we did that as well. So the permits are in hand for the development. But given where the market is, we're not moving forward with anything at this time. Quick reminder on the quality, it's a high-vol B-type quality coal. And in markets where we've experienced reasonable sales of that product in the past, that's brought in a price of $135 a ton or more for that product.

Mark M. Kane

Tim, we did spend a little bit of money in '12 relocating utilities and doing some very preliminary surface work so that when the market does recover, we can start actual development.

Timothy M. Winter - Gabelli & Company, Inc.

Okay, so roughly what sort of lead time would you need to start develop -- to start mining the reserve.

John B. Ramil

Yes, we think the installation of the shafts, the deep shafts to get at the seams, will take a couple of years, probably about 3 years until we're at a meaningful production range. And full production capability of almost 2 million tons a year, probably about 5 years from when we start.

Operator

Your final question comes from the line of Ali Agha with SunTrust.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

John, just wanted to clarify one point on your thinking with regards to the dividend, particularly your confidence level that you'll be back on the same pattern in 2014, also, linking that to your point that 60% to 70% payout ratio is what you target towards. So should I assume that you're fairly confident as well in '14 that you will be in that 60% to 70% payout ratio, and hence, looking at potentially getting back to your normal increase pattern? Or is it getting you closer there? I just wanted to be clear on your thinking there.

John B. Ramil

Yes, we're confident we're going to be a lot closer to that range than this year. Obviously, when we look ahead, get some improvement in the coal markets, get through our regulatory process at the electric company, get a little bit more growth out of Peoples Gas, we'll be back into considering dividend increases, as we have for the last 2 or 3 years, and operating within that range. But if you look, we can and we do have the ability to be on the aggressive end of that range. Because from a cash standpoint, we're in much, much better shape because of the NOL position, which Sandy pointed out, than where you'd normally be at the earnings per share level, wherever we might end up.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

So you don't necessarily have to be in that range to be considering an increase, as long as you are getting closer to it, given your cash position?

John B. Ramil

No, we don't have to be, but we expect to be back in and around that range.

Operator

Thank you. I would now like to turn the call over to Mr. Kane.

Mark M. Kane

Thank you, everyone, for joining us this morning. We thank you for your participation on the call. Thank you, Keisha. This now concludes our call.

Operator

Thank you. Again, that does conclude today's conference. You may now disconnect.

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