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Executives

Julie S. Ryland - Vice President and Investor Relations

James T. McManus, II - Chairman and Chief Executive Officer

Charles W. Porter, Jr. - Vice President, Chief Financial Officer and Treasurer

Analysts

Holly Stewart - Howard Weil

Jim Harmon - Barclays Capital

Faisel Khan - Citigroup

Energen Corp. (EGN) Q1 2009 Earnings Call April 23, 2009 10:30 AM ET

Operator

Good morning. My name Christy and I will be your conference operator today. At this time I would like to welcome everyone to the Energen First Quarter 2009 Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question and answer session. (Operator Instructions).

Thank you, Mr. Ryland, you may begin your call.

Julie S. Ryland

Thank you, Christy. Good morning. Welcome to all of you joining us by phone and by internet. Today's conference call is being held in conjunction with Energen Corporation's announcement yesterday of the results of operations for the three month ended March 31, 2009.

Our prepared remarks will include statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor Provision of the Private Security Litigation Reform Act of 1995.

Except as otherwise disclosed, the company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. All statements based on future expectations rather than all historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that may be outside the company's control and could cause actual results to differ materially from those anticipated.

A discussion of risks and uncertainties that could affect future results of Energen and its subsidiaries is included in the company's periodic reports filed with the Securities and Exchange Commission.

At this time, I'll turn the call over to Energen Chairman and Chief Executive Officer, James McManus.?

James T. McManus, II

Thanks, Julie. And good morning to everyone joining us today. At yesterday's annual meeting of shareholders, we disclosed the results for the first quarter of 2009. And I hope you've had a chance to review the news release that accompanied that announcement.

The bottom-line for the quarter was, it's great to have a strong hedge position, net income in the first quarter of 2009 totaled 95.6 million, or $1 33 per diluted share, as compared with the 116.7 million or $1.62 per diluted share in 2008.

Our excellent hedge position increased production and decreased per unit production taxes combined to help offset the impact of significantly lower oil and gas prices on the first quarter results. The average realized sales price for total production in the quarter fell 19% year-over-year that takes into account our 65% hedge position. With no hedges, we would have experienced the 50% decrease in average realized sales price.

Sell-through hedging, we were able to protect earnings and cash flows from the full impact of commodity prices. In just few moments, Chuck will go over first quarter results in more detail.

First, I would like to highlight some other developments. We've updated our estimate of Energen Resources' probable and possible reserves as of December 31, 2008. The quantities have not changed materially. We picked up 10 Bcf in the probable category and lost 56 Bcfe in possible category.

Our total unproved inventory is now 1.85 Tcfe versus 1.9 Tcfe in the prior year. We proved that some 100 Bcf of previously identified probable and possible reserves, we lost about 160 Bcfe due to lower year end prices and other revisions and we added approximately 215 Bcfe of new profitable and possible reserves, primarily in the San Juan.

We estimate that our unrisked costs are $1.24 per Mcf for probable reserves and a $1.17 per Mcf for possible reserves. After applying our own risking, we estimate that the total finding and development cost per Mcf our unproved inventories, approximately $1.80 to $2.10 per Mcfe.

Energen Resources' technical staff estimates the physical quantities of our unproved reserves at year-end. These in turn are reviewed by independent reserve engineers, also the same commodity price is used to calculate year-end 2008 proved reserves were applied in establishing the companies profitable and possible reserve estimates.

Yesterday, we affirmed our 2009 earnings guidance range of $3.10 to $3.50 per diluted share. This range assumes that price is applicable to our unhedged production will average $6 per Mcf for gas and $50 per barrel for oil, and $0.65 per gallon for liquids for the remainder of the year.

Our key assumptions are detailed in yesterday's news release. But I want to address a few of them here this morning.

We've increased our estimated capital spending plans at Energen Resources' by 17 million. We do not expect this to have an impact on production and still estimate annual production of approximately 106.5 Bcfe in 2009. Our annual estimate of per unit LOE is now $2.17 per Mcfe versus 224. This is simply the result of rolling in first quarter results. If commodity prices stay low, we may see some additional reduction in field service and production taxes.

While our utilities first quarter earnings were up year-over-year, we did experience usage declines among our large commercial industrial customer. These are basically recession related declines and were largely offset by increased revenues from our core market during the highs of the winter heating season.

We have lowered our 2009 return expectations for the utility, because we are concerned that usage will continue to be down from our LC&I customers and we will have the opportunity for significant benefits from our core market due to seasonality of those revenues.

I urge you to take note of the sensitivities we provide in our news release, relative to the impact of commodity price changes on our earnings and cash flows. This is an important part of our guidance. Our hedges are rolled in to this analysis, but we still have exposure to commodity prices that are different from the prices we assumed for unhedged production.

Our release yesterday also details our hedge position for the remainder of 2009 and briefly discusses our 2010 hedge position. As we traditionally note our earnings guidance does note include potential benefits from property acquisitions, Alabama shales exploration or stock repurchases, our guidance also makes no assumption related to the potential impairment of 42 million of capitalized unproved leasehold related to Alabama shales.

Speaking of Alabama shales effective April 1, 2009 Chesapeake has agreed to farm out to us its half interest in approximately 660,000 acres in Alabama shales. Under the terms of the agreement, we have 18 months to drill one Conasauga well and one Chattanooga well. After each well is drilled, Chesapeake will farm out its 50% leasehold interest in each shale to Energen Resources.

Chesapeake will retain a net overwriting royalty interest of approximately 1 to 2.5%, which is convertible to a proportionately reduced working interest of 25% or net 12.5% at 125% payout on a well-by-well basis. This will result in an after-payout working interest to Energen Resources of approximately 87.5%. We plan to drill two wells within the terms of the agreement and we are interested in having a partner to move forward with us.

I want to emphasize that we may still drill two well this year, as we previously discussed, but on the other hand if natural gas prices stay low, and it takes us a little longer, then we might prefer to find a partner we may allow drilling to slide into 2010. With free cash flows and strong balance sheet and more than 500 million of available loans of credit, Energen is well positioned to whether the current economic recession and downturn in commodity prices and capitalize on opportunities that may actually grow out of it.

There is little change in our cash flow outlook for 2009. After funding identified capital spending of 235 million and a small portion of our dividend, Energen Resources expects to generate in 2009 free cash flow of 184 to 214 million. Together, with 24 million of cash available at year-ended 2008. Energen Resources should have access to approximately 208 to 238 million of free cash flow by year end 2009.

Cash available to Energen Resources at the end of the first quarter is 52 million. In general, Alagasco utilizes all of its after-tax cash flows to fund these capital expenditures in the majority of Energen's dividend. With respect to our credit facilities we are very pleased that Energen's 200 million bilateral line of credit with regions has been renewed for another 364 days.

This line of credit will be allocated to 165 million to Energen and 35 million to Alagasco. We also have negotiated a $35 million line of credit with Citibank. Of that amount 20 million is dedicated to Energen and 15 million to Alagasco. The new 364 day bilateral line of credit became effective last week.

In total, Energen has access to 515 million of committed credit facilities. I think that brings you up to date on the latest developments at Energen.

At this time, I will turn the phone line over to Chuck Porter, our Chief Financial Officer, for a closer look at first quarter 2009 results. Chuck?

Charles W. Porter, Jr.

Thank you, James. For the three months ended March 31, 2009, Energen's net income totaled 95.6 million or $1.33 per diluted share. This compares with first quarter 2008 net income of 116.7 million or $1.62 per diluted share.

Please note that the prior period results did include a 6.4 million or non-transfer diluted share gain from the sale of a small Permian Basin property. Energen Resources net income for the first three months of 2009 totaled 47.1 million and compared with 72.5 million in the same period last year. Energen Resources substantial hedge position increased production and decreased per unit LOE helped offset the negative impact of significantly lower oil and gas prices.

Just a few minutes ago, James told you about our hedge -- how our hedge position held up significantly in the first quarter. As for production, Energen Resources first quarter 2009 volumes increased 9% over the same period last year. For the last several years, the company has accelerated development of its unproved reserves, primarily in the San Juan and Permian basins, the positive results of this acceleration are still being felt in 2009, even though the development pace has been slowed significantly, due to current economic conditions and low commodity prices.

We estimate 2009 production will grow 4% to approximately 106.5 Bcf equivalent, despite a reduction of identified capital spending relative to 2008 of approximately 50%. Energen Resources total per unit LOE in the first quarter declined approximately 18% year-over-year to $2.1 per thousand cubic feet equivalent. Base LOE and marketing and transportation expenses in the first quarter of 2009 fell approximately 2%, largely due to decreased compression expense and lower field service costs, partially offset by increase of loan taxes.

The biggest decline in per unit LOE came from commodity price driven production taxes, which fell 57% on a per unit basis. Per unit DD&A expense in the first quarter of 2009 increased 27% over the same period last year to $1.54 per Mcf equivalent. This was largely due to higher development cost and lower year-end reserve prices.

Per unit net G&A expense in the first quarter of 2009 declined 13% over the same period in 2008 to $0.46 per Mcf equivalent.

Alagasco, our natural gas utility generated net income of 47.5 million in the first quarter of 2009, as compared with 43.7 million in the same period a year ago. This increase primarily was due to the utility's earning on a higher level of equity. We did experience decreased usage by Alagasco's large commercial and industrial customers that is being driven by sustained economic recession. This decline was largely offset by increased core market revenues.

As James mentioned earlier, continued usage declines among our LC&I customers will likely put pressure on the utility's ability to earn within its allowed range of return on equity. Our earnings guidance for the utility reflects our expectation of a lower earned LOE in the calendar year. That is a quick run through of our first quarter results. So, James I'll kick it back to you.

James T. McManus, II

Thanks, Chuck. I want to underscore that Energen is really in a strong financial position. We're ready to pursue those property acquisitions that are good fit for us. We also are pleased with our Chesapeake's format agreement and look forward to pursuing a partner to help us move forward in Alabama shales.

With that I will ask Christy to open the phone lines for your questions.

Question-and-Answer Session

Operator

(Operator Instructions). All right, our first question comes from Holly Stewart. Your line is open, from Howard Weil.

Holly Stewart - Howard Weil

Hey guys. Good morning. Quick question on the shales, knowing that you can't give many specifics, but it seems like a pretty tough environment to get someone to make capital to a new price. So if you could just give us some color around kind of the process that you're going through and maybe your outlook as far as far as timings?

James McManus, II

Well, Holly, it is a good question. Our thought process here is we would like to have a partner, working on that, we're got the form out arrangement done with Chesapeake. We're going to be pursuing that. We needed to get that taken care of before we talk to potential partners.

It's a tough environment out there, but we're not really going to trying to strike a super hard deal. At this point, we're more interested in getting a partner who can help us develop this play if it wasn't being commercial and who may have some expert to be able to help us from an expertise perspective. So that's about all the color, I can put on it right now.

Holly Stewart - Howard Weil

Okay. And Jim, you're talking pretty quick on the call. You mentioned the drilling of the first two wells might flow into 2010. Did I hear that correctly?

James McManus, II

Well, yeah here's our thought process. Everybody knows, gas prices are pretty low right now. And there are agreement with just Chesapeake. We've got 18 months from April 1st and all we have to do is penetrate the formations in order to have the acreage signed to us. So, the way we look at it, even if we were to find something commercial in these shales, it's probably not something you'd move into full scale development at this commodity price environment anyway.

So if we're not able to -- if we look hard and we can't find a partner, it's not a lot of capital to drill these wells and go ahead and get the acreages signed from Chesapeake. And we're prepared to do it on our own. And even after that Holly, we would then go look for a partner. Now if we find something good, it'll be a more expensive deal than it's going to be right now if we can get somebody to come in. Does that make sense?

Holly Stewart - Howard Weil

Yeah, absolutely. And then I guess two other quick ones. On the acquisition market, if you could just kind of give us a little color around what you're seeing out there, may be what you'd be interested in? How the market's shaping up right now?

And then I guess one for Chuck on the, I realize the CapEx increase is very small, but on the E&P side what the incremental capital is being used for?

James McManus, II

Okay. Let me take the acquisition market for a minute. We do believe that with the state of the economy and the condition that a lot of companies are in related to tight credit markets and perhaps having balance sheets that are little bit over leveraged. We do believe that we're going to see more quality properties. We're active in that market. As you know, Holly we are seeing things that look better than what we have seen in the past. And we think this could be the best market we've seen since 1999.

With respect to what we would look for, clearly we have been a company focused on long life reserves and we would also look for properties that are in our existing areas of operations. And as know, our three biggest areas are San Juan, Permian and Black Warrior. Now we'd say, consistently we would move outside those areas for a sizable deal, but obviously it'll be nice to get one within those areas, because those are the easiest for us to assimilate. And there are the less risky, because we know the areas. We know how to operate those properties that we can execute on whatever drilling is involved in the acquisition as well so, the follow-up on that?

Holly Stewart - Howard Weil

No. That will be it.

James McManus, II

Okay. Let me kick it to Chuck on this capital

Charles Porter, Jr.

Yeah, Holly with respect to capital, we did have some 2008 wells. We thought there were going to be 2008 wells and they fell into the first quarter. We also had a small acquisition of about $3 million in the San Juan basin. And then there has been some increases in some non-operated drilling plans along with some cost overruns on some horizontal wells that kind of got away from us. And then offsetting that we did -- we made a few additional cuts of some wells that we didn't like the economics of in this lower price environment. And netting all those things together, we did have a small $10 million increase.

Holly Stewart - Howard Weil

All right, thanks guys.

James McManus, II

Thank you, Holly.

Operator

And our next question comes from Jim Harmon with Barclays Capital. Your line is open.

Jim Harmon - Barclays Capital

Thank you. Good morning.

Unidentified Analyst

Hi, Jim.

Jim Harmon - Barclays Capital

Hi. Since you are pretty much in the driver seat and the play going forward, is there anything that you will be doing differently? Do you have more of latitude to look at the acreage, than you have in the past?

And then I guess the second question would be, are there any incremental data points that would affirm that you are getting warmer or colder during the play that you'd come across since the last update?

James McManus, II

Jim, there's no more data points. And we made a very extensive and full disclosure about the total, about the results in the sales. And we do think that there are some things that can be done differently and obviously, since it was all Chesapeake's capital on the drilling side, they were in control of how that was handled. And so our hope this time is that we would take a partner, and when we take that partner, we would be much more in control of how we design these wells, and how we complete these wells, because we do have some ideas on how to go about it that are a little bit different than the first two that we tried.

Jim Harmon - Barclays Capital

And I'd be greedy and ask if you could share any of that, or do we have to wait?

James McManus, II

Well, let me talk about the Chattanooga, because we've said this. We believe upon further study, the original completion of that horizontal leg in the Chattanooga was done with a water frac primarily. Upon study of the formation and upon some consulting with outside venders such as Halliburton and Slumberjay and looking at what operators are doing up in Tennessee is become evident to us that the frac technique should have used an energized frac like nitrogen.

And that we may have in fact drawn the formation now. That's a supposition on our part. We think that's the right way to go. And as I've consistently said, we've either used the wrong completion technique or we've got rock that is a lot worse than what our cores course would have indicated and our data would have indicated, while we were drilling the well, because we're very good shares in the horizontal leg.

So that's on Chattanooga side. On the Conasauga side, our thought process is that we may want to go a little bit more lateral in these wells that the vertical frac that we did may have in fact encountered barriers that caused us not to get as extensive a frac as we wanted to. We're still working on those solutions, but we may try something a little bit more shallower. We may not go quite as deep and we may try to go lateral here as well.

Jim Harmon - Barclays Capital

Thank you. Those are great answers.

James McManus, II

Okay.

Operator

And our next question comes from Crystal Choi with Raymond James. Your line is open.

Unidentified Analyst

Good morning.

James McManus, II

Good morning, Crystal.

Unidentified Analyst

I wanted to get a general feel for the environment now in terms of cost, particularly on the completion side and can you also give an update on what your rigs schedule look like?

James McManus, II

Let me see if we can get to put our hand -- when you say rigs schedule, you mean how may do we have running in each basin.

Unidentified Analyst

Sure and when they roll off?

James McManus, II

I'm not sure we're going to be able to put our hands on that, Crystal. We'll see. Let me first address completion costs. And the bottom-line is we're not sure exactly where all these cost are headed, but the drilling rig cost dropped very sharply as we moved into the beginning of the year and the completion cost tended to lag. We are seeing a little bit of movement down on the completion cost, but they were still a lot of completion activity going on even though some of the rigs were laid off.

We hope that that continues to moderate. As Chuck pointed out, we've also seen some moderation in LOE from what we have budgeted. Of course, we'd, we said consistently we budgeted LOEs sort of at the top of the market and hoped that might be a bit lower. And in fact our LOE would have been lower in the first quarter had it not been for at the ad valorem factors, which were a big driver of LOE. And that's based on year end, previous year end oil and gas prices and since those were high, we haven't seen the decrease yet in ad valorem.

Now, let me take a guess at it. Crystal, I think we've got one rig running in the San Juan, one in the Black Warrior, one for part of year in North Louisiana and East Texas that drops. It goes probably for half of the year and then one or two rigs in the Permian. That's pretty consistent activity there throughout the year with the exception of North Louisiana and East Texas. And that's probably the best input I can give you into that. We'll check on that and be sure that's accurate and have duly call you back if it's not.

Unidentified Analyst

Okay, I was also wondering in the Permian if you're active in the Sprayberry and Wolfcamp?

James McManus, II

Yeah, what's call the Wolfberry trend, which is completions in both the Wolfcamp and the Sprayberry. We're drilling some test wells there Crystal this year. We had drilled some wells there last year. We've had very good success from a standpoint. That play is oil price sensitive. Drilling costs are coming down and as you know, it's a function really, your economics are calculated on two -- drilling cost is a very important portion of your economics and reserves are. We've got some good results from the completions. We think that the oil price needs to be higher than it is right now in order to get into full scale development on the Wolfberry, but we have a number of locations in that particular combo formation that at the right oil price, we would go ahead and drill.

Unidentified Analyst

Thank you.

James McManus, II

Thank you.

Operator

(Operator Instructions). Our next question comes from Faisel Khan with Citigroup. Your line is open.

Faisel Khan - Citigroup

Good morning, guys.

James McManus, II

Hey, Faisel.

Charles Porter, Jr.

Hi, Faisel.

Faisel Khan - Citigroup

Just curious on the production, the year-over-year production growth, most looking at the Permian Basin and then maybe your oil production, up 15% year-over-year. Can you guys give us an idea of kind of how that's likely a trend over the course of this year, what your expectations are?

James McManus, II

Well. Faisel, of course we ramped up or activity significantly last year, say 40 or 57 million, I think is capital and we're dropping off a little bit this year, so while you saw I don't know if I can address the Permian specifically we're looking right now, we saw 9% overall increase slows to four for the year. And you might say why is the quarter 9% of the year only had four, part of that's all the capital we spend in '08 that's kind of flowing into production for '09 and then when we moderate capital down, it tends to drop that back, where've only got a 4% gain.

Let us do this. We're going look to see what that well effect is, we don't have it right at our finger tips. If you've got any other questions?

Faisel Khan - Citigroup

I was just curious was that more work over activity or was it kind of new, was it new drilling activity that kind of --

James McManus, II

It's our water flood activity Faisel. It's continuing to drill producers and injectors. It's not so much work over activity as it is new wells that we've drilled.

Faisel Khan - Citigroup

Okay. Got you. I mean given where oil prices are versus natural gas prices, would be you be allocating more of your overall capital on that part of your business, rather than terms of the natural gas basis you're in?.

Charles Porter, Jr.

Well, I think you clearly got to look at that. As we move in the 2010, we think the budget we've got right now are 235 is what we want to do right now in 2009, but as we look to 2010, if the oil prices kind of hold where they are, obviously they are more attractive, they are trading more at a 10 to 12 to once. So that certainly could be a better price to allocate capital, you are right.

Faisel Khan - Citigroup

Those were 200 -- of the 200 or some million dollars of capital you could allocate more towards the oil side versus natural gas, but what's on your plans right know?

Charles Porter, Jr.

For 2009, the budget we've got is what we're going to go with. We're not doing any kind of shifting.

Faisel Khan - Citigroup

Okay.

Charles Porter, Jr.

But what I am suggesting that is as we look forward to 2010, we certainly look at the economics. And if oil prices are higher, that's going tend put more a favorable life of the capital that we spend in a Permian, all other things equal like drilling cost.

Faisel Khan - Citigroup

Okay. Got you. Okay. I appreciate it. Thanks for the help.

James McManus, II

Thank you, Faisel.

Operator

And our next question comes from the line of Jessica Chitman with Tudor Pickering & Hull (ph). Your line is open.

Unidentified Analyst

Hi, good morning guys

James McManus, II

Hey, Jessica.

Unidentified Analyst

I just had a quick question. Can you guys provide public information on your short-term credit facilities, the 364 day long because I couldn't find them?

James McManus, II

No we don't, we're a little bit unusual there. We don't have a revolver because of our historical relationships with banks that existed in Birmingham, Alabama. They are all 364 day facilities. At this point in time, most of don't have any unused fees because of the existing other business with the banks.

And the ones that we borrow with mostly from are based, their competitive bids, if you will. We ask the banks what their cost of funds are, what they want to lend, and of course they all have a kind of back staff borrowing rate that would be tied with LIBOR plus or Fed funds rate plus and or the banks prime rates. So they can have a back staff, but typically we borrow on a competitive bid basis.

Unidentified Analyst

Okay, I just have a follow-up on the -- you obviously don't answer cash flow processors. So I am just wondering as a short-term concern lasting, can you still do an acquisition with the funds you have various facilities? How do we think about that?

Charles Porter, Jr.

Let me take that Jessica. Absolutely, I mean we can finance an acquisition. As we said, we're generating minus 208 to $238 million of free cash flow. So for example let's just make up a number, let's say we do $150 million acquisition since we've got 52 million on cash on hand right now. We borrow a 100 million on those lines of credit. And in this situation, we would actually pay them off by the end of the year on that size transaction. Now if you start to get above 218 million, then you would actually have some balance on these lines of credits that you would carry that you would have to decide whether you want to term that out at a later term or whether you just want to carry it on those lines, does that make sense?

Unidentified Analyst

Yes, it does. Thank you. That's all I have.

Charles Porter, Jr.

Thank you.

Operator

And the next question comes from Carl L. Kirst with BMO Capital. Your line is open.

Unidentified Analyst

Hey, guys this is actually Michael Pelp (ph). I was -- I have just a quick question as far as first, I guess on the lines of credit, is the full 515 available. Have you guys pulled down on that already?

Charles Porter, Jr.

Now the full 515 is currently available. We have about a $100 million being fixed for the utility, which leaves $415 million that could be utilized by Energen Resources. But we ended -- we had some on the lines at December 31, but by March 31st, we were completely out of line. So the full balance is available.

Unidentified Analyst

Okay, and then on the second part as kind of maybe a follow-up on Faisel's question. When you guys are looking at acquisitions and kind of locking in returns, it would seem that if you're trying to hedge it out and keep your returns, either you'd focus on kind of oil acquisitions. Do you guys look at that going back and forth, I mean what?

James McManus, II

Yeah, good question. Let me tell you how we think about it. We would look at either commodity and I think in this environment, typically on acquisitions we've hedged out as far as four years and as few as two years, but usually we do some hedging out to lock in those returns and clearly in this environment, you certainly would think to hedge and lock in those returns, because there's a lot of uncertainty out there right now.

Now, if you think about the two commodities just for a minute, gas has a supply and a demand problem theoretically. It looks like there is a lot of supply, don't know how quickly we're going to work our way through with the rig count falling and it's also got a demand problem. We talked about our utility LC&I demand down, because of the recession.

Oil on the other hand seems to have only a demand problem. There does not seem to be tremendous oversupply and once the economy bounces back, you would think that oil prices might run a little quicker than gas, is sort of our thinking. So Mike, you have slight preference towards oil perhaps, but if you can buy gas in this low price environment at a good return and you hedged it out for several years, I think you wouldn't be bothered by gas either.

Unidentified Analyst

Now that makes sense. And then I guess just a last question. On the buyback, have you guys considered re-looking at that or anything. I mean it seems like you're generating a return of to a million free cash. So you have a lot of availability on the short-term lines. Just any thoughts?

James McManus, II

Well, what we've had so far is that we want to see what comes available in the acquisition market. We think there can be some very attractive opportunities for long-term growth. We can always implement a stock buyback strategy at anytime that we choose to if we feel like the stock is way undervalued, but our preference has been to look at long-term growth opportunities.

Unidentified Analyst

All right. Thanks guys.

Operator

(Operator Instructions). We have no further questions. I'll now turn the call back over to Mr. McManus.

James McManus, II

As always thank you for joining us this morning and for your interest in our company. I hope we will see some of you at the AGA Financial Forum in just over a week. In the meantime, if you have additional questions please don't hesitate to call and Julie Ryland would be the right contact point there. Thank you.

Operator

This concludes our conference call for today. You may now disconnect your lines.

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