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Energen Corporation (NYSE:EGN)

Q4 2008 Earnings Call

January 29, 2009 9:30 AM ET

Executives

Julie S. Ryland - Vice President, Investor Relations

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

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

John Richardson - President and Chief Operating Officer

Analysts

Carl Kirst - BMO Capital Markets

John Freeman - Raymond James

Holly Stewart - Howard Weil

Operator

Good morning. My name is Mindy and I'll be your conference operator today. At this time I would like to welcome everyone to the Energen Corporation 2008 Yearend 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 Ms. Julie Ryland, you may begin your call.

Julie S. Ryland

Thank you Mindy, and 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 year and quarter ended December 31, 2008.

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's Chairman and Chief Executive Officer, James McManus. James?

James T. McManus, II

Thanks Julie and good morning to everyone joining us today.

2008 was a year marked by economic highs and lows, and we are very pleased that Energen's earnings continued to grow during this period. We achieved our seventh straight year of record earnings in 2008. This accomplishment was supported by record performances at both our subsidiaries and by record production.

Energen issued a fairly extensive news release yesterday, and I hope you have had a chance to review it. This morning Chuck and I will highlight key points then open lines to your questions.

Increased production and higher realized sales prices were the big drivers of Energen's record earnings in 2008. Net income totaled $321.9 million or $4.47 per diluted share as compared to 309.2 million or 4.28 per diluted share in 2007. Contributing 88% of consolidated net income, Energen Resources, our oil and gas E&P unit, reported annual net income of 282.7 million and Alagasco, our natural gas utility, reported 2008 net income of 40.2 million.

As expected, Energen's fourth quarter earnings were less than in a prior year primarily due to lower commodity prices. For the three months ended December 31, 2008, Energen's net income totaled 65.3 million or $0.91 per diluted share and compared with net income of 79.4 million or $1.10 per diluted share in the same period last year.

Our substantial hedge position help mitigate the impact of the dramatic decline in commodity prices during the fourth quarter. Averaged realized sales prices for the fourth quarter production declined 9% year-over-year. However had it not been for Energen's hedges on approximately 72% of its production, average realized sales prices would have declined 30%.

Yesterday, we announce we have cut Energen Resources capital spending by 70 million going from 290 -- 295 million to 225 million. We have decided to delay the drilling of selected wells which accounts for approximately 50 million of the reduction. We then made cuts of approximately 20 million to reflect declining capital costs in response to the substantial decline in natural gas and oil prices.

The drilling we eliminated was on acreage held by production, in light of that, and given the current lower price environment, we opted to delay drilling these wells and instead increased the company's cash flows available for other investment opportunities. We estimate that the drilling capital cuts will reduce 2009 production by 1 Bcf equivalent to 106.5 Bcfe.

Energen Resources, yearend proved reserves held up well in the face of low commodity prices. We estimate that our proved yearend reserves totaled just shy of 1.6 trillion cubic feet equivalent. As we continue to accelerate drilling of our probable and possible reserve inventory in 2008, we proved out some 124 Bcfe of reserves and more than replaced our 2008 production of 102.4 Bcfe. Negative revisions two-thirds of which related to significantly lower yearend commodity prices totaled approximately 188 Bcfe.

Our proved reserves at December 2008 were priced at $5.71 per Mcf versus $6.80 in the prior year, $44.66 per barrel versus 95.98 in the prior year and $0.43 per gallon versus a $1.39 in the prior year.

Primarily due to the impact of reserve revisions on DD&A into our capital related production decline, we have lowered our 2009 earnings guidance range by $0.10 to $3.10 to $3.50 per diluted share. Per unit DD&A in 2009 is now expected to be $1.58 per Mcfe as compared to $1.52 per Mcfe in the prior guidance.

As always, please note that actual earnings in 2009 can be influenced by a variety of factors. Not included in our guidance is the potential benefit of property acquisitions, Alabama shales' exploration or stock repurchases, nor does our guidance make any assumption related to potential impairment of capitalized unproved leasehold related to Alabama shales of approximately 42 million.

To further protect our earnings and cash flows from commodity price volatility, we recently added 3.5 Bcfe -- Bcf of 2009 natural gas hedges at an average NYMEX equivalent price of $6.31 per Mcf. In total, we now have hedges in place for 65% of our estimated 2009 production of 106.5 Bcfe.

Approximately 68% of estimated 2009 natural gas production is hedged at an average NYMEX equivalent price of $8.70 per Mcf. 59% of our estimated oil production is hedged at an average NYMEX equivalent price of $72.31 per barrel and 65% of our estimated NGL production is hedged at an average price of $1.15 per gallon.

Looking ahead to 2010, we also have hedges in place totaling approximately 42.6 Bcf of gas at an average NYMEX equivalent price of $9.12 per Mcf and 2.2 million barrels of oil at a NYMEX equivalent price of $96.85 per barrel.

Energen Resources 2008 production grew 4% to 102.4 Bcf equivalent as we continue to accelerate development of our P2 and P3 inventory.

Primarily in the San Juan and Permian Basin, as I noted earlier, we have more than replaced this production during 2008 by proving up some 124 Bcfe of probable and possible reserves. We estimate that production will grow another 4% in 2009 to 106.5 Bcfe.

Energen Resources ended 2008 with a cash balance of 24 million. In 2009 after funding identified capital spending and a small portion of Energen's dividend, we expect Energen Resources to generate free cash flow of 186 to 260 million. This will result in total cash available of some 210 to 240 million when you include the cash balance of 24 million that we have at the end of '08.

These substantial discretionary cash flows will be available to help fund Energen's strategic investment opportunities including oil and gas property acquisitions and potential shale development. In general, Alagasco utilizes all of it's after tax cash flows to funds it's capital expenditures and the majority of Energen's dividend.

Energen has executed an agreement with First Commercial Bank for $25 million line of credit delegated to Alagasco renewable July 31, 2009. We also have reviewed a -- renewed for another year Energen's $25 million line of credit with Bank of New York.

Currently we are preliminary discussions with two additional banks in an effort to further expand our credit facilities. Energen's committed lines of credit currently total $515 million. 115 million is dedicated to Alagasco, 213 million dedicated to Energen, and 170 million is available to either. There is not much new to report on Alabama shales front. We still plan to invest approximately 10 to 15 million during 2009 to drill additional shale wells, test alternative completion techniques and/or complete other zones in the existing test wells.

While initial results of the initial test wells were neither positive nor conclusive, we believe additional work is in order to better determine the productive potential of the Conasauga and Chattanooga Shale plays on all (ph) 330,000 net acres in Central and North Alabama.

Details of our 2009 guidance. Hedge position earning sensitivity to changing commodity prices and revised capital spending plans are included in our release yesterday. I'd encourage you to review that information.

At this time I would like to turn the phone over to Chuck Porter, our Chief Financial Officer for a view of the financial results for 2008 and the fourth quarter. Chuck?

Charles W. Porter, Jr.

Thanks James. It is my pleasure to talk with you this morning about the very strong financial year that Energen had in 2008.

For the year ended December 31, 2008, Energen's net income totaled $321.9 million or $4.47 per diluted share as compared with $309.2 million or $4.28 per diluted share in 2007.

The current year period included a one-time 6.4 million or $0.09 per diluted share gains on the sale of Permian Basin properties in the first quarter of 2008. Energen Resources net income in 2008 totaled 282.7 million and compared with 273.2 million in 2007. This increase largely reflects higher average realized sales prices, a 4% rise in production to 102.4 Bcf equivalent, a one-time gain from the sale of Permian Basin properties in the first quarter of 2008 and lower administrative expense partially offset by higher LOE and DD&A expense as well as a higher effective tax rate due to a reduced tax benefit under section 199.

Our average realized sales prices were up year-over- year for gas, oil and liquids. We had a 6% increase in production in the San Juan Basin largely due to new drilling and continued development of our Fruitland Coal properties. Our Permian basin water flood activities more than compensated for normal declines resulting in a 1% production increase in the Permian, and production was up 18% in the North Louisiana, East

Texas area, largely due to continued field development and additional non-operated activities.

In the Black Warrior Basin, a 5% production decrease mainly was associated with higher commodity prices but that resulted in lower net volumes due to net profit calculations. Per unit LOE in 2008 increased 13% from 2007 to $2.31 per Mcf equivalent. This increase largely was due to increased price driven production taxes, increased work-over expense, increased transportation cost, increased compression and weather related road maintenance. Partially offsetting the increase in production taxes was a $0.07 per Mcf equivalent adjustment for 2005 to 2007 and the current year related to reduced severance taxes in New Mexico.

Per unit DD&A expense in 2008 increased 18% over 2007 to $1.33 per Mcf equivalent, largely due to higher development cost and to a load-back (ph) adjustment associated with yearend proved reserves. Per unit net G&A expense decreased 20% year-over-year to $0.45 per Mcf equivalent largely due to lower benefits related to the company's performance based compensation plan.

Alabama Gas reported net income of $40.2 million in 2008 as compared with 36.8 million in 2007. Despite decreased customers usage this year-over-year increase in net income was due to the utility; one, going down it's enhanced stability reserve to help compensate for large industrial and commercial load loss during the 2008 rate year to keeping its rate year; two, keeping it's rate year increase in O&M expense below the inflation based cost control measurement feature of our rate setting mechanism; and three, earning on a higher level of equity. Included in the prior year net income was a $2.3 million reduction designed to keep the utility earning within its allowed range of return on average equity at end of the 2007 rate year.

Turning next to the fourth quarter results. For the three months ended December 31, 2008, Energen generated net income of 65.3 million or $0.91 per diluted share as compared with 79.4 million or $1.10 per diluted share. This increase largely was due to significantly lower commodity prices applicable to Energen Resources un-hedged production and higher per unit DD&A expense partially offset by increased production, lower per unit LOE and lower per unit G&A expense.

Despite having 72% of our fourth quarter production hedged and therefore having limited sensitivity to changes in commodity prices, those prices applicable to our un-hedged volumes dropped significantly during the fourth quarter. Energen's substantial hedge position helped mitigate the impact of the dramatic decline in commodity prices. As James mentioned earlier, our average realized sales prices for fourth quarter production fell 9% year-over-year. However, had it not been for hedges average realized sales prices would have declined 30%.

Energen Resources fourth quarter 2008 net income totaled 60 million and compared with 73.9 million in the same period last year. Production increased 6%. San Juan production rose 8% largely due to new drillings, and continue development of our Fruitland Coal properties. A 7% production increase in the Permian was associated with our water flood development partially offset by normal decline. There was no change in the north Louisiana East Texas area in the quarter and in the Black Warrior Basin production was down 3% mainly due to higher commodity prices that resulted in lower net volumes due to net profits calculations.

Per unit LOE in the fourth quarter of 2008 decreased 7% from the same period a year ago to $1.85 per Mcf equivalent. This decrease largely was due to a $0.26 per Mcf equivalent adjustment for 2005 to 2007, and the current year related to reduced severance taxes in New Mexico, and to a commodity price derivative (ph) decrease in current production taxes.

These decreases in production taxes were partially outset by increased at loan taxes as well as higher work-over expense and increased marketing and transportation cost in the San Juan Basin. DD&A expense per unit in the fourth quarter of 2008 increased 28% over the same period last year to $1.55 per Mcf equivalent primarily due to a load-back (ph) adjustment associated again with the pricing of yearend proved reserves.

Per unit G&A expense in the fourth quarter 2008 declined 48% over the same period in 2007 to $0.31 per Mcf equivalent, largely due to lower benefits related to the company's performance based compensation plans.

At Alabama Gas, they reported net income of 5.4 million in the fourth quarter of 2008 and that compared with net income of $5.7 million in the same period a year ago.

That concludes my prepared remarks and at this time I will turn the program back over to James.

James T. McManus, II

Thanks Chuck. I don't want to overlook the fact that yesterday Energen's Board of Director raised Energen's quarterly cash dividend by 4.2% to $12.5 per share. This marks the 27th consecutive year that Energen's dividend has been raised. Our new annual dividend rate is $0.50 per share. In keeping with our dividend policy, this increase reflects projected payout of net income from our utility that is in line with traditional gas utility payouts of 65 to 75%. In addition, Energen Resources is contributing less than 5% of its estimated net income to the dividend. As you know our philosophy is to retain the majority of Energen Resources cash flows in order to reinvest them to help fund long-term growth.

Before I open up the phone lines for your questions I want to leave you with these thoughts. Obviously the US and global economies are struggling but Energen's strategic objectives and financial capacity to achieve them remains strong.

As we enter 2009, Energen offers a strong hedge position that helps to insulate our 2009 earnings from commodity price volatility. We've also got some very good hedges in place for 2010. Energen also offers 4% organic production growth, solid after-tax cash flows, a very strong balance sheet and untapped lines of credit with which to pursue our strategic investment opportunities.

At this time I would ask Mindy to open the phone lines for your questions.

Question-and-Answer Session

Operator

(Operator Instructions). And our first question comes from Carl Kirst from BMO Capital. Your line is open.

Carl Kirst - BMO Capital Markets

Thanks. Good morning everybody. James, you'd opened talking about the revisions on the reserves, 188 Bs and you'd mentioned that two-thirds were price related. Can you give us a sense of what comprised the other one-third 65 or so Bcf?

James McManus, II

Yeah, let me do this Carl. I've got Johnny Richardson with me. He's President and Chief Operating Officer of Energen Resources. And why don't you do this -- if this is okay, Carl, I'll get Johnny to do a reconciliation of where we started the year to the end of year and then specifically he can give you some color on those reserve revisions.

Carl Kirst - BMO Capital Markets

Please.

John Richardson

Thanks for the question, Carl. Yeah, I'll start out as James requested and tell that at the end of last year 12/31/07; you'll recall Energen had proved reserves of 1.75 Tcf. We produced 102.4, as James just told you, last year. We also took around 120 Bcf write-down due to commodity prices falling. So we had a demo division of that.

Now the other 65 days or so, of course, there's always adds and revisions -- there's always upward adds and downward revisions in those. But the 65 does include 2 unusual items; another 15 Bcf of that 65 was due to increased LOE, which also impacted our reserves and 30 Bcf included in that 65 number was due to sort of change in our practices in the San Juan where as our production grows we find we need to have more moving equipment, lower pipeline pressures and so forth which is a good thing, but it does cost us fuel. And so as we've looked at what we are going to do in the future we thought it was right to realize that this fuel burn which would impact us about 30 Bs. Now as an addition, we did have an add of 124 Bcf equivalent primarily from our P2 and P3 inventory and we were quite pleased with that.

James McManus, II

So Carl normally our normal noise is pretty small, it's usually in the 30 Bcf area; it's a little bit higher; at twice that amount this year but as Johnny outlined 15 of it because LOE was going to cause some of those tail life reserves to go a little non-economic. Now if LOE goes way back down to the drilling cost we'll get those back and then 30 Bs is due to the fact that we are going to be using some of the reserves for fuel in the San Juan.

Carl Kirst - BMO Capital Markets

Okay, now that's helpful. And part of where I was going, I was trying to get into what you might call a cleaner F&D number as far as on king of a price static basis. So this helps but all of that being said, we're probably still looking at an F&D sort of north of 350 as you're going to look out at 2009 seeing -- what you're seeing clearly from a CapEx standpoint, there's obliviously no reason to be pressing the accelerator on production.

But if we kind of come down to sort of 225 million CapEx, obviously we might be falling short of next year of replacing production and so; one, I was trying to just get a better sense what you guys thought maybe your F&D may tend to look like in 2009; and two, if there's has been any -- in the sense that there will be a gap presumably of replacing production, how aggressive right now you're considering in the M&A market if this is something that you think there's may more downside still to come in the general market and so you might want to wait till the second half of this year or if you are seeing M&A opportunities today?

James McManus, II

Yeah, Carl, let me start with the M&A side of things. The market has pretty much frozen right now in our opinion. There's not lot of activity. People are, obviously, not wanting to sell in this market if they don't have to, and so our judgment is the opportunities will start to come in the second half of this year. Now let's see if that plays out. If commodity prices stay low, it's our belief that there will be some opportunities to pick up some properties perhaps at prices that we haven't seen since 1999.

So we're happy to help dry powder available cash flow to look at those opportunities but I do think it will a while before they shake free because there's going to have to be some pain because obviously the sellers don't want to sell in this kind of price environment as well. So, we do think opportunities are going to come up. I think it's going to be a while before they -- before we see him. We are not really seeing anything right now and obviously we stay in very close contact with the companies who market properties, who put properties out for sale and what they -- what we are hearing from them is frankly there's just no activity right now.

Carl Kirst - BMO Capital Markets

Okay, and on the F&D?

Charles Porter, Jr.

Yeah Carl this is Chuck, let me follow up on F&D question just for second. You are right; I mean if you were to equalize the 188 Bcf of reserve revision assuming that you are going either get the price back in the future and maybe the LOE. You'd have a number that is north of $3, somewhere in the 3.15 range is -- what I have got is a preliminary calculation. And the reason that that's higher this year than you might expect as we did a lot of PUD drilling this year, and we already had those reserves booked. We don't really have a number for you for 2009 yet, we are working on our probable and possible reserves, and redoing those. But you will recall that they are typically on risk basis expected to be less than $2.50 -- around $2.50. And we'll have to take a look that when we get the new study done. We're not anticipating at this point in time any material changes to the study. And then as we move forward into 2009 and we and the drilling that we do do, the -- obviously the more that it is associated with probable those would be new reserves that we'll be adding.

Carl Kirst - BMO Capital Markets

Great. And then just a last question, if I could. Looking at the unit cost structure certainly understand the bump in DD&A. If I look at the capital budget as a proxy, it looks like well costs are coming down, drilling cost up 15%. As we look in the unit cost guidance however LOE G&A these are basically static from the last go around of guidance. Is this just sort of airing on the side of caution? Are you starting to see some drop in the G&A and LOE right now or is that something that you're expecting but just don't want to bake in just yet?

Charles Porter, Jr.

Carl it's a great question. I think you got it right. Basically we built that LOE at the time when it was in its high point. Frankly, the capital cost tends to come down first on the drilling side and the LOE tends to lag it a little bit. And so we are helpful that we have the highest number in there that it could possibly be and we hope that we will see some diminishment in those costs, but we didn't want it. We had no basis really to redo them because we've not seen the kind of decreases on the LOE side, frankly, that we've seen on the drilling side yet. But we would --

Carl Kirst - BMO Capital Markets

Okay.

Charles Porter, Jr.

I would expect to see some.

Carl Kirst - BMO Capital Markets

I appreciate the time and color.

Charles Porter, Jr.

Thank you Carl.

Operator

Our next question comes from John Freeman from Raymond James. Your line is open.

John Freeman - Raymond James

Good morning.

James McManus, II

Good morning, John.

John Freeman - Raymond James

I was trying to go over the new drilling CapEx in a little bit more detail to get kind of an apples-to-apples comparison with what it was prior to this because the prior guidance that was broken out between each of the basins included the 40 million of -- that you are describing as pay add surface facilities. And so I am just trying to see what the absolute -- like -- the actual drilling budget was apples-to-apples in each of these plays in your prior guidance to now.

James McManus, II

I think we've got that John. It may take us just a minute to put the fingers on it.

John Freeman - Raymond James

Okay. And then while you're looking up that, and just ask another question. Of the 15 B reduction on reserves due to the higher LOE. It was that primarily in one basin or was it spread out across kind of your company's inventory.

James McManus, II

Let me repeat it John, the question was and I'm going to turn it to Johnny here; the 15 Bs that was related to increased LOE but that in one particular area or is that spread out over the company?

John Richardson

It's pretty well spread out. We do see few higher lifting cost in certain areas in the Permian but pretty much -- and in -- and then in the San Juan it will be due to our higher cost for pumping as I alluded to earlier as we -- these hold on the (ph) wells as we go to that we'll make more water, we'll have more moving equipment. So the bulk of it, it's fairly spread out but the bulk of it is probably in San Juan due to the change in scope.

John Freeman - Raymond James

Okay. And then just looking at roughly what the LOE was in '07 kind of low $2 range and just given the current guidance of 224, I mean, is it safe to say that the LOE needs to get back down closer around two bucks to get any of those 15 Bs back?

John Richardson

Well, I don't know the exact tipping point of that but, yes, we would assume that -- these things work in tandem of price and LOE or both in the equation to figure your economic limit. So movement either way on one of those but I would expect we would need to see some material decrease in LOE to have that 15 Bcf disappear, yes.

John Freeman - Raymond James

Okay.

James McManus, II

Well you have -- I think what he was saying, John, is you have to. If you drop back to the same level we were at last year you would expect that you would be close to getting those back whether it's right at $2 or not it's pretty complicated calculation and that was the major driver for losing it. But, yeah, if it drops back down we don't have a chance to get those back. I do have, John, the numbers that you asked for just a minute ago, if you like those now?

John Freeman - Raymond James

Yes, that'd be great.

James McManus, II

Okay, well, as it relates to the Permian basin, we had previously 103 million of capital for drilling 126 net wells. We now have 86 million of capital drilling 122 net wells. For the San Juan basin, we had 100 -- previously, we had 103 million for approximately 57 net wells. 35 of those were horizontal in side tracks and 22 of those were vertical.

We now have in the San Juan 60 million for approximately 48 net new wells, 26 of which are horizontal on side track and now 22 vertical. In North Louisiana and East Texas, we had 24 million drilling 8 net wells. We now have 17 million for 5 net wells.

The Black Warrior numbers remained exactly the same at 12 million for 30.5 net wells. And of course that information was in our previous press release dated December 10th and then the new information is in our most current press release, January 28th.

John Freeman - Raymond James

Great, that's all I had. Thanks a lot, James.

James McManus, II

Thank you, John.

John Freeman - Raymond James

Bye.

Operator

(Operator Instructions). Your next question comes from Holly Stewart from Howard Weil. Your line is open.

Holly Stewart - Howard Weil

Good morning. I just have one quick follow-up here. Can you talk a little bit about or give us a little more color, I guess, on the relationship of the production cut to the CapEx cut. It looks like you are only losing about 1 B in production and your cutting about $50 million of drilling CapEx?

James McManus, II

Yeah, Holly, we took out some of the higher cost well that we had in the program and of course some of those were designed to be drilled later in the year. So, the impact on production is fairly modest from doing that.

If you sort of -- that's the general answer, but if you look at the ratio of reserves that we were going to bring on line during the year for the expenditure of that capital and you take what we're losing for the $50 million, the relationship holds up pretty well percentage wise.

Holly Stewart - Howard Weil

Okay.

James McManus, II

We were going to bring on about 5 Bs this year for the 280 million and that was about 18% when you look at what you are knocking out. You reduced it to about 18% and when you do that math, it's a little under Bcf so the math works out pretty reasonably.

Charles Porter, Jr.

Yeah, actually whereas James is talking about the 280 number and the 295, 280 was actually for drilling and development. That's the part of the -- portion of that capital. So, if you reduce it by 50, that's 18%, which gives you 9/10ths of the revision just of the intuitive math there.

Holly Stewart - Howard Weil

Got you. All right, thanks guys.

James McManus, II

Thank you.

Operator

Your next question comes from Carl Kirst from BMO Capital. Your line is open.

Carl Kirst - BMO Capital Markets

Hey guys, just a quick couple of follow-ups, if I could. Just kind of given where gas prices are right now if in the unfortunate situation in March it was kind of a 450 number, is there any dollar impairment we might be facing?

James McManus, II

Carl, I don't think so, and let me explain the difference there. Most of your write-downs are occurring right now and we've seen several of them on full cost companies who are required to obviously value their reserves at the end of the year at whatever the price is without escalation.

If you are on the successful efforts method and Chuck's going to check me out on this, be sure I get it right, I am looking at him, you're allowed to escalate prices and so it's reasonable to assume that prices are going to escalate and not stay flat and so generally successful efforts companies it's much more unlikely that they would have an impairment because they can escalate prices. Chuck, would you add anything to that?

Charles Porter, Jr.

Well, I would add a little bit. That is actually correct in his analysis. I mean we are successful at this pursuable (ph) cost and we do get to escalate prices and we routinely look at that especially at yearend when we have new reserves and we took a look at those areas and put in some strip prices as of that time and we were fine. So we are not anticipating any problems.

Carl Kirst - BMO Capital Markets

Okay, yeah, it was the escalator that I was forgetting. So I very much appreciate that. And then just --

James McManus, II

Carl -- Carl?

Carl Kirst - BMO Capital Markets

Yeah.

James McManus, II

Carl just to follow back up. You had to do... you do this test on a freeholder property basis and not to say that there couldn't be something out there that at some low price but not the bulk of your reserve, that could be an isolated situation that could occur but I am not aware of one.

Carl Kirst - BMO Capital Markets

Fair enough. And then just kind of two, perhaps, questions or data points we'll see in (ph) ultimately but with respect to the now new proved reserve number, do you have a percent prove producing I assume it's going to be going up little bit from last year but 85, 86, do we have a number on that?

James McManus, II

We do have that number. If you give us just a second and we'll put our finger on that one for you.

Charles Porter, Jr.

Hey, Carl, we should be about 84% proved developed reserves at the end of the year.

Carl Kirst - BMO Capital Markets

Okay. And then any sense right now in sort of the generic PV10 calculation what you have slotted in for future development costs?

James McManus, II

Are you talking about as part of the overall reserve disclosure?

Carl Kirst - BMO Capital Markets

Yes.

Charles Porter, Jr.

Or proved reserves?

Carl Kirst - BMO Capital Markets

Yeah.

James McManus, II

We do have that Carl, it's going to take me a second to dig that out. Just hold on one second.

Carl Kirst - BMO Capital Markets

Well that was the last question I have, so if you wanted to move on, please feel free.

James McManus, II

Well I think what we'll do --

Charles Porter, Jr.

It looks like -- it will be around the $480 million level and that includes all of our future P&A also. So I --

Carl Kirst - BMO Capital Markets

Right.

Charles Porter, Jr.

So I don't have that available to break out for you but grand total will be around 480, 485 million.

Carl Kirst - BMO Capital Markets

Great, thanks Chuck.

Operator

(Operator Instructions). At this time there are no more questions in the queue. I'll turn the call back over to James McManus for any closing remarks.

James McManus, II

Thank you, Mindy. As always, thank you for joining us this morning for your interest in the company. If you have additional questions, please don't hesitate to call, and I appreciate your involvement. Thank you.

Operator

This concludes today's Energen Corporation 2008 yearend conference call. You may now disconnect your line.

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Source: Energen Q4 2008 Earnings Call Transcript
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