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TECO Energy (NYSE:TE)

Q2 2012 Earnings Call

August 02, 2012 9:00 am ET

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

Dan Eggers - Crédit Suisse AG, Research Division

John Kiani - Deutsche Bank AG, Research Division

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

Andrew Bischof - Morningstar Inc., Research Division

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Operator

Good morning, my name is Wendy, and I will be your conference operator today. At this time, I would like to welcome, everyone to the TECO Energy's Second Quarter Results and 2012 Outlook Conference Call. [Operator Instructions] Thank you. Mr. Kane, you may begin your conference.

Mark M. Kane

Thank you, Wendy, and good morning, everyone, and thank you for joining us for TECO Energy's Second Quarter Results Conference Call and Webcast. 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 the slides for this presentation are available on our website at tecoenergy.com and on the Investors page. The presentation will be available for replay through the website approximately 2 hours after the end of the presentation and will be available for 30 days.

In the course of our remarks today, we'll be making forward-looking statements regarding our financial outlook for the remainder of 2012. There are a number of factors that could cause our actual results to differ materially from those that we'll discuss as our outlook and expectations today. For a more complete discussion of these factors, we refer you to the discussion of the risk factors in our Annual Report on Form 10-K for the period ended December 31, 2011.

There is additional helpful information related to the state and local economies contained in the appendix to today's presentation.

Today, Sandy Callahan, TECO Energy's Chief Financial Officer, will cover our results and our outlook. Also with us today to participate in answering your questions is John Ramil, our Chief Executive Officer. Now I'll turn it over to Sandy.

Sandra W. Callahan

Thank you, Mark. Good morning, everyone, and thank you for joining us on another busy day for utility earnings reports. I understand that there are at least 10 companies releasing today, so I'll keep my remarks brief. I'll cover second quarter results, local and state economic indicators and our revised guidance for this year.

In the second quarter, net income was $73.1 million or $0.34 a share, compared with $77.5 million or $0.36 in 2011. On a year-to-date basis, net income in 2012 was $123.6 million or $0.58 a share compared with $129.2 million or $0.60 last year. The most significant factor impacting the year-over-year comparisons, in both the quarter and 6 months, were the effect of milder weather on electric sales.

Tampa Electric reported lower net income in the 2012 quarter, despite having had the strongest customer growth we've seen since late 2007. Since it began to turn at the end of 2009, customer growth has been on a solid trend up. And for the second quarter this year, reached 1.3%.

Retail net energy for load in the second quarter was 2.3% lower than last year. Total degree days were 6% below last year, primarily due to a wet and mild month of June, including the effects of Tropical Storm Debby the last week of the month. This negatively impacted sales to residential customers, although commercial and industrial sales were up. Tampa Electric also had higher depreciation expense due to normal additions to facilities and higher operations and maintenance expense.

Peoples Gas reported higher results than last year and customer growth had reached 1.2% in the second quarter. Weather isn't a factor in the second quarter gas consumption. And we saw a firm sales increase in every retail segment, residential, commercial and industrial, as the Florida economy continues to improve. Peoples also benefited from lower O&M expense in the quarter compared with last year.

For the unregulated companies, TECO Coal's results for the quarter reflected higher margin, but lower sales volume from last year. The average selling price for the quarter rose to $94 per ton due to met coal prices locked in when the market was strong and higher average steam coal prices following the expiration of a below-market contract at the end of last year. The second quarter price was below the $96 average price expected for the full year, as the sales mix this quarter was more heavily weighted to steam coal due to the timing of metallurgical coal shipments which will occur in the second half of the year.

The all-in cost of production was $84 per ton, just below the middle of the cost guidance range, after experiencing higher first quarter cost associated with idling some facilities in that quarter. TECO Coal has been successful with its cost control action to offset the effects of spreading fixed costs over fewer tons.

Second quarter net income at TECO Guatemala was higher than 2011, reflecting higher contract and spot sales volume and lower operating expenses. Other positive impacts, although smaller, include higher earnings from the TECO's gas pipeline that serves Jacksonville Electric and lower parent interest.

We are revising our earnings per share guidance for the year to a range between $1.20 and $1.30, excluding any non-GAAP charges or gains that might occur. This revision is due to the effects of the mild year-to-date weather on Tampa Electric, and the expectation that the unsold tons included in our original projections at TECO Coal will not be sold this year. This range allows for some variation in weather and customer usage at the utility and for cost and the timing of contracted shipments at TECO Coal.

The primary factor driving Tampa Electric's outlook is the year-to-date effect of the unfavorable weather on residential revenues. The rainy weather that hurt June continued into July as well. As a result of the lower residential revenues, we expect Tampa Electric will earn near the bottom of its allowed ROE range of 10.25% to 12.25%.

Peoples Gas, because of the rate design implemented in its 2009 rate decision, is less weather and volume sensitive and should be able to earn at or above the middle of its allowed 9.75% to 11.75% ROE.

Our outlook assumes that customer growth generally continues in line with the year-to-date trends at both utilities, and that weather for the remaining 5 months of the year is normal. The outlook also assumes that the current economic and housing market conditions in Florida generally continue and doesn't contemplate a major economic slowdown.

So now turning to what we have been seeing in the local and state economies. If you're interested in seeing graphically some of the trends I'll be discussing, there are some graphs in the appendix that do that. The unemployment rate in the state continued to improve in the quarter until leveling off in June, unchanged from May at 8.6%. As a point of reference, it was 9% at the end of March and was 10.7% only a year ago. The civilian workforce continues to expand, up 0.4% over the past year. And the number of those employed statewide is up 2.7% compared with last year.

In Hillsborough County, Tampa Electric's primary service area, unemployment also improved early in the quarter, declining from 8.5% in March to 8.4% in May. In June though, it ticked up to 8.8%, a seasonal pattern we've observed in prior years when the school systems close in May and school bus drivers and other school system employees are off for the summer.

Over the last 12 months, Florida has added almost 71,000 new jobs in the field shown on the slide. During the same period, the Tampa area has added more than 23,000 new jobs, which is the strongest growth in any of the major metropolitan areas in the state. It's possible that employment in the Tampa area is benefiting from increased hiring ahead of the Republican National Convention, which will be held in Tampa the last week of August. And the final point on this slide, consumers are spending more in general, with taxable sales up 5% year-over-year in the 12 months ended in June.

The housing market also continues to improve. Metrostudy, a firm that tracks new home construction trends expect new home starts in the Tampa area to be 5% to 15% higher by the end of 2012 than in 2011. And the actual year-to-date data supports those projections. You can see on the building permit graph in the appendix that new single-family building permits are trending up, with a very strong start to the summer.

Statewide, Metrostudy is reporting increased residential construction activity in virtually every major market. And there are even published reports out of South Florida of a resumption of condo tower construction. Growth in existing home resales continued, with resales in the 12 months ended June 2012, climbing 6% compared with the same period last year. The inventory of homes actively on the market, as is tracked by the Greater Tampa Association of REALTORS, was actually below 4 months at the end of June. At the end of March, it was 6 months, which already was considered a healthy market.

The average home resale price bottomed in early 2011 and has been increasing pretty consistently since then. The average selling price in the 12 months that ended in June was 3% higher than the comparable period a year ago. Like other areas of the country, we've seen a higher level of foreclosures in the Tampa area this year, presumably as the banks have gotten past their documentation issue.

Foreclosures spiked in February through May. But by June, had declined to previous levels. The percentage increase was high. But to put it into a practical perspective, the volume increase during that spike was the equivalent, in total, of about 1 month of housing resales activity. So as resale inventory at its current low level, it doesn't appear that the foreclosure spike we saw is likely to cause a major disruption.

So overall, what we've seen recently in the state and local economies and housing markets has continued to be positive.

For TECO Coal, we've revised our sales forecast, down to a range of 6 million to 6.3 million tons this year, based on the expectation that the roughly 10% of sales that were uncontracted at the end of the first quarter will not be sold this year. We are fully contracted at 6.3 million tons. So the range simply recognizes the potential variability of delivery schedule. The sales mix is now expected to be about 45% net PCI and stoker coals, since the unsold tons included PCI and some lower grades of met coal.

For the year, the average selling price is expected to be slightly less than the $96 per ton, and the production cost is still expected to be in the range of $83 to $87 per ton for the year. We expect a somewhat higher average selling price of $97 for the second half, as some shipments of specialty coal have shifted into the second half of the year based on customer requests.

At TECO Guatemala, we expect normal operations at the San José Power Station for the remainder of the year until the fourth quarter, when we will have an extended planned outage for a major steam turbine overhaul. When that outage is completed, we expect the turbine to have a better heat rate and to have a small amount of incremental capacity, which will be available for sale in the spot market. Although the impact of the outage is minimized because it happens in the fourth quarter when hydro plant availability reduces the opportunity for spot sales anyway, it will impact results about $4 million compared to 2011.

The challenging coal markets and issues at some other coal producers, have heightened interest among some investors regarding our outlook for TECO Coal beyond this year and have surfaced some misconceptions about the coal business. So before I close, I would like to address a few of these.

First, TECO Coal is margin driven and not volume driven. Our future production in sales will be based on market conditions and per ton profitability. We'll mind what the market demands and is willing to pay an appropriate price for it. This means that we can't provide an outlook on future volume until we see what the market is.

For 2013, we already have 2.5 million tons of thermal coal, contracted and priced in a range of $75 to $82 per ton. At this volume level, we're in pretty good shape for thermal coal sales for 2013. For various reasons, including more surface sources, less washing, less depth, thermal coal cost less to mine than met coal, and are profitable at these prices. We haven't priced our met coal for 2013 yet, as the normal contract cycle for domestic met coal is late third quarter or early fourth quarter. And for the past several years, we have been selling most of our met coal domestically.

For 2014, we have 1.2 million tons of thermal coal contracted and priced above $80 per ton. We would like to get more thermal coal contracted for 2014, but the good news is that we have 1.5 year to get it done and futures prices indicate an expectation of some market strengthening in 2013.

To put some perspective on what we have invested in the coal business. At year end, our investment in mines equipment and reserves, net of depreciation was only about $200 million. And we don't have significant legacy liabilities. We're a nonunion operation, with benefits programs that are similar to the other TECO Energy companies. There's no debt specific to TECO Coal. And the reclamation liabilities for deep mines and preparation plants were about $20 million at year end. While the surface mine reclamation is done primarily as a current operating expense as we mine.

In short, over the years, we've invested moderately in this business and have managed it conservatively. As a result, we've earned strong returns on our investment and limited our financial exposure.

And I'll close with our upcoming investor communication activity. In September, we'll be meeting with investors on the East Coast in the mid-Atlantic at Boston areas. And the following week, we will be in New York at the Bank of America Merrill Lynch Investor Conference. 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 Kent Carnelite [ph].

Unknown Analyst

So I had a question that is somewhat unrelated to your main topic of discussion. Can you give us a view on what you're seeing in the impacts across the businesses of low gas prices. If you can address things like switching in generation sources and any impacts on customer usage at the gas business from lower prices?

John B. Ramil

Kent [ph], this is John Ramil. And let me address those. First of all, at the electric company, we are seeing our natural gas units, which are highly efficient combined cycle units, competing more with the coal companies for dispatch. And where, traditionally, the coal units would handle all of the baseloads and then the gas would kick in intermediate. The gas units are more competitive and they're running more. And I think, probably, utilities all over have seen that change in their mix a little bit. It's helped to keep customers' overall cost down because the fuel cost, confident of our rate, has stayed down. At the gas company, putting aside weather and the mild winter we had, we're seeing -- expected a strong use by our customers. But we're also seeing more and more customers wanting to switch from petroleum-based BTUs to natural gas BTUs because of, not only the current price differential, but expected future price differential. We are building a significant pipeline to an industrial customer up in the Northeast Florida area for just that purpose. They're going to be using natural gas in their operations rather than petroleum and other products moving ahead. We've seen the same type of interest from other businesses like nurseries or plants and things like that and other industrial processes. And of course, very, very significant interest from those that operate fleets of vehicles and converting their petroleum-based product vehicle fleets to compressed natural gas. And we've been in that process for about 1.5 year and we have things underway. And in about another year, we will have helped our customers put in enough compressed natural gas fleets to be the equivalent of serving about 27,000 new homes with natural gas. So we're seeing a lot of interest in that area. The negative effect we've seen from natural gas prices has been in the coal business as has been reported broadly in the industry that has reduced utility consumption of coal, which has left them with higher inventories. And so utilities are not buying as much coal and that's the biggest negative effect we see from the natural gas prices. But as Sandy said earlier, we're in the fortunate position of having timed our contracts for steam coal, such that we contracted in a pretty positive period and have nice contracts for this year, next year and 2014 at prices that we can make a good reasonable steam coal margin on. Sandy, you add anything to that?

Sandra W. Callahan

No. Very comprehensive.

Operator

Your next question comes from the line of Dan Eggers.

Dan Eggers - Crédit Suisse AG, Research Division

On the Tampa -- you've kind of come in through the lower end of the earned ROE, how much of that do you suppose, from an ROE perspective, is based on weather? And how much of that is just the fact that after so many years of stay out, it's just getting harder and harder to stay within the band?

John B. Ramil

Dan, this is John. We see the majority of that right now attributed to weather. You saw where we've been for the first part of the year. And we continue to have success in controlling our cost. A little bit of frustration with those things that are hard to control like benefit and pension cost, but our team is still doing a good job there. But the majority of it is driven by weather. In the first half of the year, July continued to be a wet month. We had our board meeting yesterday. We went to pick up our board members at the hotel and it was raining. And we told them welcome to our year, here at the electric company. And when we look at the balance of the year, we can have strong sales, hopefully, in August and September. But those are the months where you could really make it up. Beyond that, you can't make it up the whole. So the majority of it is weather driven. When we talked about -- we came out of our last rate case, we talked about our desire to stay out of rate cases and we needed some things to happen and one of them was to stay on our program to be efficient and we'll continue to do that. The other is we need to get the customer growth back up to the longer term expected 1%, 1.5% customer growth and that is starting to happen, but it's lax. It's been a little bit longer than we would have liked, but we're getting closer to that. And we also talked about, hopefully, we don't have weather hurting us. And unfortunately, last year and this year, weather has been hurting us.

Dan Eggers - Crédit Suisse AG, Research Division

So John, you mean you look at the 2013 in kind of a normal weather or do you have comfort that you're just going to get back to the middle of the ROE band or is it -- or you're kind of migrating toward a lower part of the band outlook?

John B. Ramil

Dan, that would be our objective. But if the mild weather drags on. You can only -- you're run out of the low hanging fruit on efficiencies. So hopefully, that'll turn around.

Dan Eggers - Crédit Suisse AG, Research Division

Okay. And then, obviously, there's a ton of questions around coal. But let me just maybe try and ask a couple and leave some more to others. But when you look at the idea of flexibility for 2013 of only producing volumes as margin allows. How much flexibility do you have kind of around the steam you've already committed? Is there ancillary coal that comes out of the ground that you're going to have to find a market for or can you really tailor production to specific markets? And how much flexibility do you have on the high-quality met to produce while not taking on the cost and the market impact of producing lower quality PCI or steam?

John B. Ramil

We believe we have pretty significant flexibility and I think we've shown that, Dan. We have in what a 3- or 4-year period have ranged from now roughly 6 million tons to 9 million tons in our production capabilities. And we've actually been making a lot more money as we've gone down it, and that was Sandy's comment. But we're looking at margin and net income and not volume. From time to time, the amount of contractors we use and what they can demand. And the strong coal markets has been frustrating. That also gives us the flexibility to do the things that we've done. And we think we can throttle up and down a fair amount and still remain profitable. As long as there's some reasonable pricing in the market. And we've shown that. One of the things, although we're not pleased with the numbers coming out of our coal company, on a relative basis, I think we're doing okay. And the thing I'm most pleased about is the success we're having in controlling our cost. We have spread fixed costs over fewer tons this year and that's been a challenge. But other than the early part of the year, January and February, as we transition from a little bit of a restructuring and a reduction in tons, our team there has been beating their targets on cost per ton. And they're focused on that and we're going to continue to do that moving ahead. And hopefully, stay on that bottom half of the range we provided.

Dan Eggers - Crédit Suisse AG, Research Division

I guess, one last question Sandy. You made a comment in '13 that $75 to $82 a ton for the steam coal, it was still profitable against an $84 average or $84-plus average cost. Should I infer from that, that your kind of the cost of producing steam is going to be in the low-, mid-70s and that would put cost of producing met and PCI below 90 just on an averaging basis?

Sandra W. Callahan

You can't do a really simple averaging on this. The reality is that when our folks contract, the sourcing of the coal is very mine specific because the physical properties and chemical properties are specific to every contract, and that makes them specific to a mining location. And so that the cost associated with mining those coals probably ranges from something like, I don't know, low-70s to high-70s. And every contract and the sourcing of every contract is evaluated for its specific profitability when we sign up for it. So it's there's a wide range of cost in the coal business.

John B. Ramil

There are. But in general, Dan, our steam products are coming from thicker steams, which keeps the cost lower. All of the steam product, unlike the met, is not run through the prep plants. So you save that cost and we get higher recovery from each ton taken out of the ground from our steam activities. And more of it is coming from the surface line as well. So there's -- it's all shifted towards the lower end.

Sandra W. Callahan

But your conclusion that you've got a lower price per steam coal embedded in that $83 to $87, and a higher price for the metallurgical coal is absolutely on point, but I can't put a finer point on it than that.

Operator

Your next question comes from the line of John Kiani.

John Kiani - Deutsche Bank AG, Research Division

Could you talk a little bit more about the specialty coal side of the coal business? I was trying to get a better handle on the pricing and the sales commitment or the hedged profile. I was looking at some of these Australian hard coking coal prices and it looked like the 4Q settlement was coming in around $179 or $180 a ton. And I guess, historically, I've noticed that some of the prices were $250 a ton or more or something in that type of range. Can you help me understand what prices you're realizing in 2012 in this specialty coal portion of the business? And how we should think about what that pricing might look like next year in '13 based on where we're seeing that 4Q settlement at this point?

John B. Ramil

John, we don't sell the same quality as that Australian hard coking coal. The only company in the U.S. that gets anything close to that benchmark is Walter out of Alabama. So we -- virtually, everybody in the U.S. discounts off of that Australian benchmark. So it's relatively meaningless to us, other than the fact that it does set a market expectation. When we were pricing our 2012 metallurgical coal contract, that benchmark was around $225. That was back into the fall of 2011.

John Kiani - Deutsche Bank AG, Research Division

Got it. Okay. So then if we're looking at your met coal portfolio and thinking about PCI and the other coals that you sell, stoker for example and whatnot. How should we think about just, I guess, the trend in pricing is another way, I'm just trying to get my arms around it, what we're realizing in '12 versus what the trend looks like in '13. Could we use sort of the percentage change that we're seeing in this Australian hard coking coal? Understanding that's sort of like a rule of thumb proxy or is there another way to think about it, please?

John B. Ramil

I don't know that there particularly is. I mean, we did contract for our metallurgical coals in the latter part of last year. That would be our expected timing again this year. I think everybody knows that markets have softened since that time. But we still need to see what happens to the balance of this year. And more importantly towards the end of this year when our U.S. customers will be looking to buy for next year and then even into the first part of next year when our international customers would be looking to buy.

Mark M. Kane

The other factor is there's virtually no spot market in met coal right now, so it's impossible to determine what the discounts off of the benchmark are currently.

John Kiani - Deutsche Bank AG, Research Division

Got it. I see. Okay. Great. And one more question please. Could you -- I apologize if you already discussed this, clarify there were some commentary in the press release about the Guatemalan operations and that the new guidance range assumed normal operations in Guatemala. But then I think I saw somewhere else where it was talking about some additional O&M or other cost that were going to be incurred in Guatemala later in the year, could you please explain that?

John B. Ramil

Yes. We've been talking for several quarters now about a planned steam turbine overhaul in 2012. And that is going to occur in the fourth quarter of this year and has been factored into our guidance all along for this year, and that has not changed.

Operator

Your next question comes from Ali Agha.

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

John or Sandy, could you remind us what is the current rate base for Tampa Electric and Peoples Gas?

John B. Ramil

Tampa Electric is just under $4 billion and Peoples Gas is just over -- it's around $550 million.

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

Got it. And then secondly also, would you remind us on an annualized basis, what's been your shipment volume for the metallurgical coal? Has it been around 3.5 million tons a year?

John B. Ramil

Including PCI, it's in that ballpark, yes. Has been.

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

Okay. And then John, I understand the points you've made about all the availability that would come in and looking beyond '12. But just directionally, given what you're seeing today and what you've contracted for et cetera, is it fair to say that we should think about '13 and '14 maybe being down years for coal before we see an uplift? Just directionally, how are you looking at your business?

John B. Ramil

I think we're the same to better on the steam side, given what we have contracted. And the met market is still to unfold later this year.

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

So that would imply -- I mean, should we assume that the stuff that you've contracted on the steam side, obviously, you're going to ship that, but to be conservative, is that what we should presume how the steam outlook at least for next year?

John B. Ramil

Yes. I think what we gave you on the slide is pretty specific about the volumes and the pricing on our steam in the next couple of years.

Mark M. Kane

It was contracted specifically.

Sandra W. Callahan

And there will be a demand, clearly, for the pure met coal that gives us opportunities for a very profitable sales in that sector of our business. It's just not clear at this point in time where our total volume will be, and particularly as it relates to PCI coal.

John B. Ramil

The PCI is the one that's going to have the most vulnerability as it has this year.

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

Okay. More particularly, when you talk about coal to gas switching, and you alluded to that in your comments as well, $3, 3.50, maybe a high $3 range for central app coal seems to be the switch point, if you will. If you look at the forward curves and they do imply gas going back up maybe even to $4 by '14, I don't know if anybody puts any credence into that, but is that impacting the market? Are you looking at folks thinking differently for the next 12, 24 months given the forward gas curves?

John B. Ramil

The general expectation that we're seeing in our utility and what we hear from others and we're approaching the time to file for fuel adjustment here in Florida is the expectation that prices will move towards that $4 a million BTU range for natural gas.

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

And last question. What's the latest on the Polk plant retrofit?

John B. Ramil

The latest is we're right where we've been talking about being now for several quarters. The Polk expansion, everybody will recall, is the addition of the steam side of a combined cycle unit to 4 existing combustion turbines at our Polk site, about a $700 million project, with an additional roughly $100 million of AFUDC on top of that going into service in the 2017 time period, and increase our generating capacity about 350 megawatts. We think very competitive, highly efficient generation addition. We are in the process of preparing to file for the need for that project. And included in the public service condition, rules and requirements for that is that we go out with an RFP and seek other offers to buy power for resources that might replace that or to be done instead or deferred that. We are getting close towards the end of that RFP process and that would take us towards a filing of our need certification later this summer. And we are on that same path we've described from the beginning.

Operator

Your next question comes from the line of Andy Bischof.

Andrew Bischof - Morningstar Inc., Research Division

You mentioned some of the factors moving slightly against you in weather and customer growth. Is it still your intention to hold off until 2016 for a rate case?

Sandra W. Callahan

Well, just to clarify those points, customer growth actually has been very much on a trajectory that's supportive of our long-term view of that. And weather really drove usage in the residential class. But we don't have any specific time frame associated with any future regulatory activity. We don't have regulatory deals as FPL and Progress that require that you go in at some point in time, in the future. And clearly, the book end is that if we do, as a result of the need process go forward with new construction that we go into service in 2017, we would need rate relief associated with that. So that's kind of the outside part of that. The other factor is continued growth on the revenue side from just underlying growth and we could use a little bit of help from weather from that. And then our ability to continue to manage cost to kind of stay out in that interim period, and the jury is still out on that.

Andrew Bischof - Morningstar Inc., Research Division

Okay. But you'd like to hold off as long as possible?

Sandra W. Callahan

Well, I think we always would like to do that.

Andrew Bischof - Morningstar Inc., Research Division

Quick question on coal, and this regards to your $65 million coal development that you've had. Are you rethinking development cost on that? I know that development costs are relatively immaterial, but has your thinking changed in regards to that?

John B. Ramil

You're talking about the new metallurgical coal reserve to TECO Coal?

Andrew Bischof - Morningstar Inc., Research Division

Correct.

John B. Ramil

We targeted -- we're still working on planning and engineering on that. But we targeted around about $160 million investment to develop those reserves over about a 2- to 3-year period. We don't have anything different than that at this point in time. But we'll watch where the market is closely, in terms of timing that activity. What we are doing though, on a real-time basis, is we are pursuing the permits to make the development of those reserves happen. And if you'll recall, we do not need any surface mine permits or any of the EPA permit, only State of Kentucky permit. And that's the main activity for this year on that process.

Operator

Your next question comes from the line of Steve Fleishman.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

You may have answered some of these questions and I missed it. But just in terms of the guidance reduction for this year, the $0.10 a share, can you maybe give a rough split between the coal impact and the utility weather impact?

Sandra W. Callahan

Sure. If you simply look at the coal metrics with really very -- no meaningful change in the expected average selling price and take the middle of the cost guidance range. A 1 million ton shift down in the volume expectation is about $0.04 probably. And Tampa Electric is behind last year currently about $0.03. That was residential revenue, weather driven. And honestly, Steve, those are the biggest components of that $0.10 change in range. Because it is a range, but those are specifically kind of how you can think about it going there.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

And I guess, second question is just to a degree we're in a weaker economic environment where there's pressure on the coal pricing and met pricing. Often that also means the diesel pricing might be a little weaker and things like that. I mean, how much flex is there for cost of production to potentially go down? Next year, is there a lot of embedded continued upward pressure?

John B. Ramil

Steve, we still have some upward pressures that we've had before. Even though we hedged the diesel prices with the lack of surface permitting we're extending jobs and transporting product further. And over time, we've gone from about 1.5 gallon per ton of coal diesel to closer to $2 per ton of coal. So that had upward pressure. Natural gas prices have been down, which is helpful on explosives. But ammonia prices were up, which goes the other way. And diesel prices although directly we hedge it, at the rates I talked about earlier, it still affects other things like the lubricants and belting and those types of things. On the other side, I think there's a little bit -- it didn't happen immediately, but potential relief on labor cost as the markets have been softer. And as we shifted production and moved production less overtime, less contractors and that's been helpful in allowing us to control the cost of the levels that we have. So it's a mixed bag of upward and downward pressures, but our objective is to keep it down, obviously.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Okay. One other question just -- is there a way, I don't know if you have this number handy, but how much allocation of kind of parent cost would be attributed into the coal business?

Mark M. Kane

The most direct cost to the allocated interest, which is just an allocation from parent, which is just under a $1 a ton. Now there are parent overhead costs that are allocated as they are allocated to everyone of the operating companies. But I don't have that number handy, Steve.

Operator

Your next question comes from the line of Paul Cole [ph].

Unknown Analyst

My question is on Guatemala. And during the quarter, there was a media report that the government there was contemplating the nationalization of energy assets. Can you give us an update on the political situation there, whether there's any substance to the story and whether it's developed into anything more definitive?

John B. Ramil

I'm not familiar with that report. The political and regulatory activity as we see it, with respect to our business, has been pretty stable. The country has gone through an RFP process for new generation and the future. And there were many, many bidders and many, many people interested in getting into that market. I haven't seen any details on it.

Unknown Analyst

Has that RFP been completed?

John B. Ramil

They went through one round of it and have extended it to later in the year.

Unknown Analyst

Is there a schedule for the final decision there?

John B. Ramil

I don't think there is. It's just been pushed off until later in the year.

Operator

And there are no further questions at this time.

Mark M. Kane

Wendy, thank you very much. I'd like to thank you all for joining us on our call today. We are going to finish early, so you have a chance to get a breather before the next call starts at 10. Thank you all for joining us today.

Sandra W. Callahan

Thank you.

Operator

This concludes today's conference call. You may now disconnect.

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