Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Legacy Reserves LP (NASDAQ:LGCY)

Q4 2008 Earnings Call

March 5, 2009 4:30 pm ET

Executives

Steven H. Pruett – President, Chief Financial Officer & Secretary

Cary D. Brown – Chief Executive Officer & Chairman of the Board

Paul T. Horne – Executive Vice President, Operations

Analysts

John Kang – RBC Capital Markets

Michael Blum – Wachovia Securities

Ethan Bellamy – Wunderlich Securities

Pavel Molchanov – Raymond James

John Kang – RBC Capital Markets

Yves Siegel – Aroya Capital

Richard Roy – Citibank

Steve Pfeiffer – Private Investor

Operator

Ladies and gentlemen thank you for standing by. Welcome to the Legacy Reserves fourth quarter and 2008 annual results conference call. Your speakers for today are Cary Brown, Chairman and Chief Executive Officer, and Steve Pruett, President and Chief Financial Officer. At this time all participants are in a listen-only mode. Following the call, there will be a question-and-answer session. As a remainder today's call is being recorded today March 5, 2009.

I will now turn the conference over to Mr. Pruett. Please go ahead, sir.

Steven H. Pruett

Thank you for joining us everyone. Welcome to Legacy Reserves LP's fourth quarter and 2008 annual earnings call. Before we would begin we would like to remind you that during the course of this call we will make certain statements concerning the future performance of Legacy and other statements that will be forward-looking as defined by securities laws.

These statements reflect our current views with regard to future events and are subject to various risks, uncertainties, and assumptions. Actual results may materially differ from those discussed in these forward-looking statements and you should refer to the additional information contained in Legacy Reserves' Form 10-K for the year ended December 31, 2008 which will be released on March 6, and subsequent reports as filed with Securities & Exchange Commission. Legacy is an independent oil and natural gas limited partnership headquartered in Midland, Texas focused on the acquisition and development of long-lived oil and natural gas properties, primarily located in the Permian Basin and Mid-Continent regions.

I will now turn the conference over to Cary Brown, Legacy’s Chairman and Chief Executive Officer.

Cary D. Brown

Thanks Steve and thanks to our friends and unitholders for joining us today in these historic times. We got a really good operational quarter. We delivered record fourth quarter production increase in production 966 barrels a day from the third quarter. And I’m really pleased with our quickly our operating team has reduced expenses. Production cost dropped from $22.61 a barrel in the third quarter to $16.74 a barrel in the fourth quarter including ad valorem taxes. Given current prices, we expect production expenses and capital cost to continue to fall in 2009.

We acquired $50.2 million of properties in the fourth quarter, we hedged approximately 85% of the related expected production at average prices of $108.90 per barrel and $8.10 in Mcf for a period of four years. We invested $14.5 million in development projects, including drilling a 11 gross and 5.5 net wells. Well, I am pleased with the performance of our third and fourth quarter development projects that contributed 966 barrels a day increase to our quarterly production. We executed $25.4 million of projects in the second half of 2008 during a period of high capital cost and falling commodity prices. There was no way to predict the dramatic decline in prices and although the wells we drilled are expected to produce over the next 50 years this may not have been the optimal time to drill.

The elevated level of growth capital investment in the fourth quarter coupled with a $7.3 million unfavorable impact due to a one-month lag in our swap settlements resulted in a 0.02 times coverage for our fourth quarter distribution. Given our maintenance cap target of 20% of adjusted EBITDA, we consider about $3.5 million of our fourth quarter as development capital spending or maintenance capital and a $11 million balance was considered as discretionary or growth capital. Excluding the growth capital implies a distribution coverage of 0.7 times our fourth quarter distribution.

Furthermore, considering a one-month lag effect in the swap settlements would provide a distribution coverage of over 1 times. Our annual distribution for 2008 was 0.94 times based on $32 million of development capital expenditures. However, if we only look at maintenance capital of about $20 million, and our 2008 annual distribution coverage would have been 1.27 times as we mentioned on our last call, our fourth quarter was impacted by lower than average percentage of volumes hedged, which will return to normal levels in the first quarter of 2009, we didn't hedge all of our acquisitions many of those on our fourth quarter acquisitions, we didn't start some of those hedges until January of 2009.

We also have about a $10 a barrel increase in our hedged oil prices from 74.62 in the fourth quarter to 84.61 in 2009. This all will help us with our 2009 coverage. Our Board of Directors has approved a 2009 capital budget of $20 million, reduced from $25 million previously announced. This is predicated on the improvement of oil and gas prices to $50 a barrel and $5 an Mcf by mid-year. Should prices continue to trade significantly below these levels, further reductions in our capital budget to $15 million will be considered. We are currently being pretty cautious with our drilling capital. We have drilled two wells in the first quarter, but have no further plans to drill wells in the first half of the year on our operated properties. We are watching capital cost and we expect that these costs will continue to fall in this tough commodity environment.

We will continue to perform well workovers, recompletions, and restimulations on existing wellbores, which generally offer higher rates of return on capital than drilling and help us offset our natural decline. As capital costs are expected to decline and as we shift a larger portion of our capital investment from drilling to behind pipe and workover projects, the productivity of our capital is expected to increase relative to 2008 when we experienced elevated costs and a higher percentage of our development capital was spend on drilling.

If you look back we increased our distributions from $0.41 per unit in our first full quarter following our initial public offering in January of 2007 to $0.52 starting in the second quarter of 2008 and continuing through the full year of 2008. We made the last increase in July to $0.52 a unit when we're looking at $120 barrel oil prices and $10 per Mcf gas prices. Today we are looking at $40 and $4 gas. Needless to say, the landscape has changed. For 2009, our oil swaps and collars average $84.61 a barrel on approximately 72% of our expected 2009 oil production and we averaged $7.78 in Mcf on 64% of our expected natural gas production.

We expect our cash flow from production and our hedges to provide coverage for our 2009 distribution and support our borrowing base on our credit facility. However, given the semi-annual borrowing base redeterminations that we are subject to, we continue to evaluate the best use of our cash to maintain financial flexibility. Should our borrowing base be lowered more than expected due to potentially lower bank price forecasts, we may be required to reduce our outstanding debt. Reducing capital expenditures will be our first step, the second step could involve a recommendation to the Board reduced distributions to achieve the desired debt reduction.

If we lower our debt levels and prices recover, we will be in a position to take advantage of the acquisition market and continue to grow. All in all, given the dramatic change in landscape, I believe that our decision to be conservative on our debt levels along with four plus years of hedges has positioned us to weather this current storm and prosper in the future. I will now turn it over to Steve to discuss our fourth quarter and annual results.

Steven H. Pruett

Thanks Cary. We are pleased to report unaudited preliminary financial information extracted from our 10-K, which we will file tomorrow. I will make comparisons of the fourth quarter 2008 to the results of the prior quarter and the third quarter of 2008 along with some annual comparisons. This information is contained in our earnings release and for a more detailed disclosure, we encourage you to access our Form 10-K on our website and it will also be available in the EDGAR system tomorrow, Friday, March 6.

Comparing our fourth quarter of 2008 to the third quarter, adjusted EBITDA decreased 24% to $17.7 million from $23.4 million due to lower commodity prices in the period and the timing of commodity swap settlements that Cary discussed previously. Production increased 13% to 8,553 barrels of oil equivalent per day from 7,587 barrels of oil equivalent per day due to a combination of acquisitions closed beginning the quarter and our elevated development drilling activities.

Net income was reported at $127 million or $4.09 per unit this was supported by a $230.4 million unrealized gain on our future commodity derivatives offset by $76.5 million of impairment and DD&A of $30.1 million, which was driven by the dramatic reduction in oil and natural gas prices during the fourth quarter. In the third quarter, we reported net income of $228 million, which included $222 million of unrealized gains on our future commodity derivatives as well as the $9.4 million of unrealized losses on our interest rate swaps pertains to the fourth quarter that's another impact on our, reducing our net income in the fourth quarter. Cash settlements received on our commodity swaps were $1.4 million in the fourth quarter, compared to cash payments to our counterparties of $19.8 million in the third quarter.

As Cary said a lot of the different the quarter makes. Adjusted EBITDA as I mentioned totaled 17.7 million in the fourth quarter, the decrease was driven primarily by reduction as I mentioned in prices. With regard to the settlement of our commodity derivatives, our natural gas and NGL swap gains more than offset cash losses on our oil swaps for the fourth quarter. We swapped 64% of our produced oil and natural gas and NGL volumes in the fourth quarter, compared to 71% in the third quarter. Again Cary discussed the lag effect on it to give you a few more details. In October, we settled and paid $3.4 million to our counterparties for our oil and NGL hedges that pertained to September contracts.

While our receipts on our December swaps paid to Legacy in January of 2009 totaled $3.9 million. These January receipts are recorded in the first quarter of 2009 though these receipts pertaining to contracts over the December production month. This lag does not exist for natural gas derivatives as they settled during the production month. So, it's a combination of this $3.4 million and $3.9 million, which gives us the $7.3 million of cash, an effect that's attributable to our production and most hedging activities that fell outside the quarter fell into the quarter at the beginning and fell outside of the quarter at the end.

Our sales for the fourth quarter were $34.4 million from hydrocarbons, which compares to a $65.6 million in the third quarter excluding the impact of commodity derivative settlements, 13% increase in sales volumes that’s our higher production volumes were more than offset by 53% decrease in prices per Boe. Realized oil prices in the fourth quarter were $54.53 excluding our hedges, compared to a $115 in the third quarter, including the effect of our settled oil swaps, oil prices were $51.22. So, we had oil hedge losses in the quarter and oil hedge losses in the third quarter drove by our effective oil price of $73.19. Realized natural gas prices in the fourth quarter of $4.77, compared to $10.37 per Mcf in the third quarter including the effect of the swap settlements, the prices would have been 697 in the fourth quarter saw an improvement and 961 per Mcf in the third quarter, which is decrement through our unhedged price.

Production cost including ad valorem taxes for the fourth quarter declined $16.74, a 26% reduction from the third quarter peak of $22.61 per barrel. The decline was driven by reduced workover activity, which was an elective managed aspect of our cost along with the reduction in vendor costs as industry activity declined with lower commodity prices in the fourth quarter. Hourly and daily rates charged by vendors continue to decline in this quarter and we're expecting to have that lower lifting in production cost in the first quarter of 2009 with declines through the year as we, if we see continued weak oil and natural gas prices.

Depletion, depreciation, and amortization costs increased to $38.25 per barrel in the fourth quarter from $18.74 per Boe in the third quarter driven the reduction in our reserve volumes that's the denominator, the numerator, we add back the production over the period, the numerator is the production over the period, the substantially lower and lower pricing environment, the commodity pricing environment drove our reserve volumes down as previously mentioned, compared to the reserve volumes carried at the end of September to calculate DD&A.

I will now shift to comparison of the annual results of 2008 to those of 2007. Adjusted EBITDA increased 42% just shy of a $100 million as compared to $70 million in the 2007 period, the increase was driven by three factors, increased average prices over the year, increased oil and natural gas volumes related to property acquisitions and our development programs. Production increased 53% to 7,582 Boes per day from just shy of 5000 Boes per day in 2007. Net income was a $158 million, reported for 2008 or $5.17 per unit, compared to a loss of $55.7 million in 2007.

Unrealized gains on our future commodity derivatives are major contributor to this net income with $217 million of mark-to-market impact or gain on our commodity derivatives over 2008 where we reported unrealized commodity derivative losses of $85 million in 2007. Unrealized losses on our interest rate derivatives were $9 million in 2009 so that negatively impacted our reported net income. Distributions attributable to the fourth quarter of 2008 paid in February of this year were $0.52 per unit and that compares to $0.45 per unit in the fourth quarter of 2007 or 15.6% increase year-over-year.

For the 12 months ended December 31, 2008 oil and natural gas sales were $250 million that compared to $112 million in 2007. Average realized prices in 2008 excluding our oil hedges were $95.16 per barrel, compared to $70.65 per barrel in 2007. Including the effects of losses on our oil swaps in 2008, while realized oil prices were $72.16 per barrel, compared to $67.58 per barrel in 2007. Realized natural gas prices were $8.60 in 2008 and $7.02 per Mcf in 2007. Including the effects of gains on our natural gas swaps we realized $8.80 per Mcf in 2008, compared to $8.48 in 2008. These stated results include the natural gas basis swaps that we use to improve the effectiveness of our gas hedges.

For the year ended 2008, we had hedges on approximately 70% of our production, at a weighted average oil price of $72.80 per barrel and $8.14 per MMBtu. For 2008 our aggregate production costs including ad valorem taxes was $18.74, an increase from $14.96 in 2007, when we were in the lower oil and natural price environment and we've had elevated levels of industry activity in 2008 that drove our cost up. G&A expenses in 2008 decreased to $4.11 from $4.63 in 2007 primarily due to the efficiencies we gained from our growth in spread and fixed costs over a larger wellcount and larger production.

Actual G&A expenses for 2008 were 11.4 million, which included $1.1 million of non-cash compensation expense on options and restricted units. We expect that our non-cash comp expense will be considerably lower in 2009 with the depressed trading prices for our equity. We experienced a dramatic aided reduction in proved reserves from 32.1 million barrels at year-end 2007 to 30.8 million barrels at year-end 2008. This includes a downward revision of 8.1 million barrels equivalent due to reduced oil, NGL, and natural gas prices that we discussed.

We did add 8.6 million barrels equivalent through acquisitions based on the year-end price of $44.60 per barrel and $5.60 per MMBtu and we also had production in 2008 captured from our reserves of about 2.8 million barrels equivalent. Our standardized measure decreased to $235 million at year-end 2008 from approximately $691 million year-end 2007 due to the decline in oil, NGL, and natural gas prices. The change in prices cause a $456 million reduction in our standardized measures, you can see a bulk of a change is driven by reduction of commodity prices net of higher production costs.

Our proved reserve volumes and standardized measure calculated on these significantly lower year-end prices, compared to the year-end 2007 oil price of $95.98 per barrel and at year-end gas prices of $7.48 per MMBtu. Neither of the decline in proved reserve volumes nor the decrease in standardized measure takes into account the fair value of our commodity derivatives positions, which increased from a net liability of $82 million at year-end '07 to a an asset of a $135 million at year-end 2008.

Fortunately for us our, the value of our hedges did account for in our borrowing base and I will talk more about that in a moment. Our reserve volumes and standardized measure based on the year-end prices due to the existing rules from the SEC, however, our operating cost and capital cost incurred over the prior 12 months were elevated due to the higher industry activity levels and higher factory cost including electricity, steel and diesel fuel. The mismatch between using low year-end oil and gas prices for the projection of our future revenues, compared to using the year average cost, operating capital cost related to the high commodity prices during the year is a mismatch that reduced our reserves production ratio from 14 years at year-end 2007 to a calculated 10 years at year-end 2008.

Furthermore, based on current oil and natural gas prices approximately half of our proved undeveloped reserves became uneconomic due to the elevated capital costs just posting depressed year-end oil and natural gas prices. However, if oil, NGL and natural gas prices improve from the year-end 2008 levels, we would expect our reserve estimates to improve significantly due to revisions in changes to prices. That's to say a lot these reserves are calculated to be loss, but we expect to be producing the same wells for many, many years to come and should we have oil and gas prices, average oil and gas prices for the year of 2009, which will be using the new SEC standarized measure methodology, we would expect to see some restoration of these so called economic reserves.

Now moving to depletion, depreciation, amortization and accretion. The severe loss in proved reserve volumes increased our DD&A rate. The DD&A rate is determined by the annual net hydrocarbon production divided by the sum of the year-end proved reserves adding back the annual production. So, the write-off rate increase are significantly due to the decline in reserve volume and the DD&A rate inclines or increased to $22.82 per Boe from $15.66 in 2007.

To the extent that proved reserves are restored due to higher oil and natural gas prices in the future and/or lower production costs, the DD&A rates could be reduced in the future. As previously discussed the combination of low year-end prices increased production and capital costs reduced the calculated economic life of the properties. This reduction in economic life and lower net revenues associated with lower oil and gas prices was the primary cause of impairment on a 101 of our 239 fields, which amounted to approximately $77 million, an increase from $3.2 million of impairment in the year ended December 31, 2007.

Since the close of the third quarter, we've acquired approximately $50 million of properties adding about $526 Boes per day of production, 74% of which is all our oil and natural gas liquids and a 100% of the acquired reserves were proved developed producing. These assets are similar in nature to our existing properties and fit very well into our established footprint.

Moving to the credit agreement, we are encouraged we are middle of an extension of our credit facility. Our credit facility expires on March 15, 2010 thus we are anticipating that event and seeking an extension to our credit agreement, we held the bank group meeting on February 26 we are encouraged by the turnout of 15 banks at that meeting. We expect a reduction in our current borrowing base below the $410 million level effective since November of 2008. However, we expect that redetermined borrowing base will be low in excess of our $300 million of debt outstanding.

The turmoil in the financial markets has made it difficult for many lenders to extend credit, particularly to enter into new lending relationships. However, we expect to be successful in securing enough commitments from existing members of our bank group along with potential new banks to extend the term of our credit agreement into 2012. We expect the cost and terms of this extended credit facility to be less favorable than our current terms due to the tight credit markets and the bank's higher cost of funds. We expect both the interest rate margin and the upfront and commitment fees to increase, but we do not expect to change in our covenants.

While the interest rate margin over LIBOR charge for our banks will increase, our unhedged cost of debt excluding fees is expected to be approximately 3.5% to 4.5% based on current floating one and three-month LIBOR rates of 0.5% to 1.5%. We have LIBOR swaps in place through 2013 on $264 million of our debt, which averages 3%. Thus our effective interest rate is expected to average approximately 6% on this hedged portion of our debt, excluding fees. We expect the extension process of our credit agreement to be completed at the end of the first quarter.

Maintaining liquidity is our first priority along with the sustainability of our assets. We thank you for your support. We appreciate your continued patience and we encourage you to review our earnings release in full and to read our 10-K, which will be filed tomorrow. At this time, we would like to turn it back to the moderator for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). We will take our first question from John Kang with RBC Capital Markets.

John Kang – RBC Capital Markets

Hi. Good afternoon everybody.

Steven H. Pruett

Hi, John how are you.

John Kang – RBC Capital Markets

Good. Thanks for asking. While I guess as well as it can be with the new administration kind of encouraging or lack of encouragement for new drilling out there, but I guess we will see what happens with the Energy Bill. I had a quick question on when you were doing your extension agreement or that initial meeting just without naming names just wondering any surprises with the banks that showed up any new banks, any banks that you had before that did not show up kind of just overall kind of get a sense?

Steven H. Pruett

No surprises, I would say that we are recently invited new banks, we actually don’t need them from a calculation standpoint if all the banks would continue to shoulder the burden they have, we would be in great shape, but given that we expect a modest or rate decrease in our borrowing base. However, we've had some mergers and we anticipate a possibility of one bank possibly falling out of the credit facilities so to speak due to their parent problems and that's why we invited extra banks we are encouraged by the interest of these other banks, but we don't anticipate all of them to join, we have a couple of relatively new banks to our facility that actually want to increase their commitment. So, at this point no surprises, but we have built enough cushion to allow or some surprises to come in this environment, everyday you open up the Wall street Journal or Financial Times there is a big surprise and we don't want our unitholders to be surprised by having a bank show up without the money so to speak at the end of the month and we are accommodating that with the mixture of shoulders to bear the load.

Cary D. Brown

And we are not in a, we've got another year on our credit facility, we are not in a crunch where if somebody at the last minute didn't show up, we expect to be have a successful process and think its good to do at a head of time, but we are not, no concern on that part from company's part.

Steven H. Pruett

It will be successful due to the way, when we have very strong hedge in banks and those are the market we have a very strong, your bankers in our facility and they are very strong and we have an excellent dialogue, we don’t rely on our agent to maintain all the relationships, they have good relationships, we have them directly as well. So, we have been taking the pulse along the way and we will have again backup so that I think we will have a very successful closing at the end of the month and it will cost more, but it still very cheap capital relative to all of the other top alternatives in the capital markets.

John Kang – RBC Capital Markets

Definitely, cheaper than higher, that it sounds will your interest rate margin be around 3% given some of your estimates you have in here?

Steven H. Pruett

Yeah that's a good math there John.

John Kang – RBC Capital Markets

Well its simple. And then I guess the borrowing base, do you expect that to be around the same time as the extension agreement or…

Steven H. Pruett

Yes. We are doing that in conjunction given that we will extend it towards the end of the month for determination period its normally April 1 so we are doing those simultaneous. So, our bank group meaning included our engineers and or I should say the bank engineers are in a thorough review of our reserves, all the banks have our internal reserves run on their various bank price forecast. So, we have pretty good sense of where the borrowing base is and we are not publicly disclosing that, we want our banks, we don't want to gun to our bank said, but we are pretty confident the number that we have out there is achievable. I think really the more delicate are in today's time is making sure we got a upfront fee and a spread that clears everybody’s internal hurdles and that’s really where most of the dialog is right now to make sure everybody is at a level that clears their credit committees.

John Kang – RBC Capital Markets

Great. And then I guess just in terms of I may have missed this early on in the call, but I was wondering were there any reserve additions to the drill bit and if so, if you had some quick math and had some finding cost on that?

Steven H. Pruett

We haven't done that, but tomorrow morning take a look at our small disclosure and if you want to talk to the math of math, we would be glad to do that, but that will be out in the public domain in the morning, take a look at that strong discloser I also always encourage every one to take a three year look at F&D cost like John S. Harold does because there is a surprisingly large impact of prices on those reserves from the drill bet plantic and revision fee to performance. So, there are years where prices increases lower F&D to unsustainable level and there is years like this where price decreases, show an excessively high F&D and you really got to smooth out all the noise caused by price changes. So, while there is a category called revisions due to prices, the impact on the reservers book due to drilling or completing or improving a wellbore that really get impacted as well.

John Kang – RBC Capital Markets

Okay. And I look forward to that and then just a last question for me if I can let others ask, in your budget when you go from $25 to $20, I know in the past you don't really give production guidance, how much of an impact to 2009 production would that be and then if you would go from 20 to 15 as you maybe alluded to, just in the case, what type of production impact would that cause?

Steven H. Pruett

It with, the difference of $20 and $25 I would be surprised, if we don't see a 20% reduction in capital cost. So, I don't know how much that would impact, we haven't done it that way, so I can't quote a number that that impact this, but I don't expect that will have a meaningful impact on production the difference of 20 to 15, but we are really looking at every project on its own merit, right now drilling doesn’t make a lot of sense. So, we are going to do the things that makes sense and if that means we have been less than 20 million that's what it will mean, we can also use that capital that we have set aside to make an acquisition if that's a better way to go and in this market that really might be a better way to go. I would expect that 20 million we are going to be relatively flat on production.

John Kang – RBC Capital Markets

Right. If you had a same percent of reduction definitely. And I guess I apologize one more question since you talked about acquisition, is there much to stress selling or data rooms or any potential out there or what are you seeing currently?

Steven H. Pruett

Yeah. We really do, I was really surprised we didn't see much in December and January, started seeing things in February and it really seems like you're starting to heat up as borrowing base season has come around so, really excited about opportunities we see out the key is finding the right capital and you may have to use a different structures then accessing the equity markets as we've done in the past in order to make some acquisitions, but I think there will be plenty of acquisitions out there and the distress is starting to show.

John Kang – RBC Capital Markets

I guess as far as you're even more pronounced as the smaller the producer you see out there I guess?

Steven H. Pruett

It has more to do with our debt levels than their size?

John Kang – RBC Capital Markets

Okay.

Cary D. Brown

John one response further on your capital budget question, the impact on production as we term our capital budget, our capital becomes more productive that to say that we are funding the behind pipe projects that we're continuing to fund those the projects that fall off or whatever I would say would be the marginal drilling projects not necessarily marginal, but not as productive in terms of rate of return or return on invested capital, and thus we, it's more like going back to the old days of our credit sectors, the Brothers Production Company, where they drill very few wells at very low F&D cost at very productive capital and we were able to maintain our production in that ‘9, 2004 timeframe with only a 12% reinvestment rate. And that's the kind of model that we were adopting again for 2009 as one that's more workover and re-completion, restimulation oriented where we get a lot more paying for our bucks so to speak and that's what we are confident even at a $15 million level, current prices and with the expect to continue to decline in capital costs that we will be able to maintain our production.

John Kang – RBC Capital Markets

Okay great. Good answer. And thanks for taking my questions.

Steven H. Pruett

Thank you, John.

Cary D. Brown

Thanks John.

Operator

We will go next to Patrick [Inaudible] with Stifel Nicolaus.

Unidentified Analyst

Can you guys hear me?

Cary D. Brown

Yes Pat.

Unidentified Analyst

How are you guys doing?

Cary D. Brown

Great.

Unidentified Analyst

Good. Beginning with, and actually I am going to take up my headset. Can you guys here me now, sorry?

Cary D. Brown

Yes.

Unidentified Analyst

All right. Sorry about that. First of all, just kind of holding all else and assuming your borrowing base remains about 300 million in oil and gas I guess the $5.50 levels that you guys spoke about in the release. Do you expect to be able to maintain the distribution at as well also or do you still think a reduction in the distribution is likely?

Cary D. Brown

We have not, we haven't been able to maintain the distribution, I don't believe because of our hedge position will be a function of can we do it as we will stretch test in different price environments it will be a Board decision to say is it wise to maintain it in this environment and are you are better off having excess liquidity to take advantage of the situation so I think we are watching oil prices, we are watching how cost comedown and we have taken all that into account to decide, what we would recommend to the Board and so I think its right now we are in a great shape and that we wouldn't have to cut the distribution, it's a matter of its prudent to do so in this environment, you can always go back up when the prices really go up, but the last thing we want to do as a company is to be in a position, where the bank is telling us as a management team what we need to do and so I think you guys see us be aware of that opportunity and where what could happen there and deal with that, but we are not sure where we are going to go with it.

Unidentified Analyst

Okay.

Steven H. Pruett

I would add Pat just from a modelling standpoint, the plan that we have in front of us with the recovery to $50 from $5 shows the coverage and calculating a borrowing base on a $50 million or $50 long-term price outlook works, but as Cary said it really comes down to Board level decision quarter-by-quarter we don’t provide distribution guidance for good reason because we live in such a volatile commodity price environment, a volatile capital market environment that we want to keep all of our options open and with liquidity being the number one goal, but rest assured from a modelling standpoint we have coverage at a in a $50, $5 price environment in the mid-year and feel good about where our banks would be in a $50 and $5 price environment as well we'd still have liquidity.

Unidentified Analyst

Okay. I guess kind of pushing on the same point just to add if I may, if you were to decide it was prudent to cut your distribution is that something where you would you guys may still pay a portion of the distribution or is it simply, just the holding off on paying it until the environment looks a little better.

Cary D. Brown

I will say the distribution is a Board decision not management, we would make recommendations. I have not seen many set of circumstances that would, that it looks to me like I could be prudent to cut the distribution completely. You would be looking at a situation, where you're talking about is it better to pay down a little debt so, now you're under coverage, you're trying to anticipate the bank's price debt, six months out and see where you are going to be, but I haven't seen anything that says you would not pay a distribution and not pay a meaningful distribution.

Steven H. Pruett

Yeah turning the sales, we think is better than having to pull the sales down, because of the bank's come backing figure overdrawn and you don't, you have to spend distributions entirely, that's why we want to manage our liquidity and not have the banks manage our liquidity for us.

Unidentified Analyst

Sure. I guess speaking to the credit faculty and the revolver, is it really the hedging gains that you have right now that's given you confidence that you're going see them come back and affirm the borrowing base above the $300 million?

Steven H. Pruett

Certainly, that's an element of the calculation we get approximately 65% credit on the PV9 of our hedges, so its very helpful and given that they're in a very positive position relative to the bank's outlook and price it's a very meaningful contribution to our borrowing base.

Cary D. Brown

In 2008, you got hit with an environment where cause all year along we’re high because of everything it was just running up and you kind of have this unusual escalation in cost and then right at the end, you have to calculate your borrowing base on those high costs and a really low price. If you go back to a low price all year along, cost are going to come back inline and you will add a bunch of reserves, but in this, this particular window, it doesn't look very good, but I think you will add a lot of, when you roll forward a year, you will be looking at cost, a year from now, which if prices stay down will be cost will be significantly lower than what we experienced in 2008.

Unidentified Analyst

Sure. Kind of leads me to my next question, if you were to incorporate the new SEC standards in calculating proved reserves, the average price for the full year, do you guys have any sense of what your reserves may have looked like in under that scenario?

Cary D. Brown

That's a pretty easy one Pat. If you look at the small disclosure in the back of our 10-K, we lost 8.1 million barrels due to revisions in price, price last year was around 90, basically what you do is you take your year-end reserves and run them at the old price and that's eliminated 8.1 million barrels that took out about 456 million of value and year end price last year was approximately $96 per a barrel and $7 in change on gas and that's not too far of the average price for the year, its close to years, its close to a $100 of barrel. So, it's a pretty good approximation we pick up a little bit more than 8.1 million barrels if you went through the math, but the small disclosure is really going to lead you to that answer.

Unidentified Analyst

Okay. Fair enough thank you very much for that. I got a couple more and then I'll hop off, you guys mentioned on the, I mean you did go into some detail on DD&A especially as a percentage of the fourth quarter. I mean I know and asking this question realizing that you guys can provide guidance is what we kind of expect from DD&A is there a run rate or something we can be looking at that would give us a kind of good idea of what that may look like?

Steven H. Pruett

Yeah. The DD&A will be, the production volumes you can predict pretty easily we’re pretty stable and flat profile unless we acquire and we haven't done any acquisition this quarter so that was fairly easy, the real question is, what's management anticipation of prices at the end of the quarter, and given that we've pretty much hit all of the ceiling tests this round and the prices don't pull back from where they are today, there shouldn’t be a lot more impairment, which means we won’t knock off more reserved volumes of the denominator. So it will be pretty static until such time that prices improve, and since restores oil and natural gas volumes back to the reserve balance and that makes the denominator larger the write-off rate smaller and you’re still pretty much multiplying it by the same book basis, so it’s going to be high as long as prices are where they are but if prices recover, look for that prices recover in the $60 to $70 range, it with the pull back more costly to historic levels of DD&A.

Unidentified Analyst

Okay I appreciate that. And then I believe I heard you guys as you spoke about interest expense, there was a $9.4 million non-cash loss related to your interest rate swaps?

Steven H. Pruett

Yeah.

Unidentified Analyst

I think you corrected that?

Steven H. Pruett

We did and that was in the fourth quarter and we didn’t highlight that prominently in our earnings release, so I regret. That. It was a significant number. It’s a reflection of the continual decline in the LIBOR swap market. We are very encouraged or at least from a sense of inflation will at some point wear its ugly head given the amount of treasury financing the federal government is doing to finance the stimulus package and the bailouts. And while we are carrying about a 2.5% negative interest spread today on those swaps, in time, we think those will be in the money and we will provide some visibility on the cost of our business over a 5-year period. But that basically reflected the change over the quarter in the forward LIBOR swap markets at September 30 versus December 31. And I don’t see the swap market. I’m no expert in the swap market, but if the swap markets stays static, that mark-to-market will remain relatively flat. If the short market erodes and comes the direction of our swaps, then we’ll have a non-cash gain in subsequent quarters. So that's the reason the reported interest is so high in the quarter. You got to back out that $9.4 million of unrealized loss, which was treated as expense in the interest line.

Unidentified Analyst

Sure. Well, I appreciate all your guys color, and here’s the 2009. Hopefully things look a little better.

Steven H. Pruett

I appreciate your support in following us.

Unidentified Analyst

Have a good one, guys. Thank you.

Operator

We got our next question from Sharon Lui with Wachovia.

Cary D. Brown

Good afternoon, Sharon.

Michael Blum – Wachovia Securities

Hi, it’s actually Michael Blum sorry.

Cary D. Brown

Hey Michael.

Michael Blum – Wachovia Securities

Just one question really. When you consider ways to increase your liquidity in the event that you had to do that. Can you talk about when the opportunity of the cost of reducing your distribution versus potentially monetizing, at-year hedges that are in the money right now to pay down debt?

Cary D. Brown

Michael. We’ve looked at a lot of those models and right now the forward strip is pretty good, moving up and to the right, and so, when you look at the insurance you would lose by removing those at-your hedges versus how much headway you would make on your debt, probably don't get as far, if you can get all the way out of debt that’s one thing but four years feels like a pretty good timeframe for this thing to recover, and knowing that you’re in good shape for four years feels really good to be as a manager and an owner of the Company. So I’m not worried about will we recover. I’m worried about the timeframe that we recover so we just want to make sure in this period where there’s some uncertainty that you get to call the shots and no one else calls them for you.

Steven H. Pruett

And Michael I’d add to Cary’s statement and that the five-year swap curves is about $57 a barrel on average. So if you unwind today you’re fundamentally betting on, in a way, $57 at the bottom. And it happens that before a curve becomes $45 a barrel, you’ve left, say $100 million on the table of insurance that you monetized.Now what some companies are doing is putting in replacement swaps, which again you unwind these premium hedges at $85 a barrel on average, or $88 a barrel wherever they are. And you replace them with less valuable insurance. If you talk to the bankers of the companies that have done this, they’ve primarily done it for two reasons. One they are worried about counterparty risk, particularly in the early stages of the financial crisis. We see or hear less of that and now what we are hearing is they are unwinding long dated hedges as a means to avoid a covenant violation particularly, debt-to-EBITDA covenant violation and those swap proceeds help EBITDA. That's sort of a selling the future to get through the present scenario and hoping for price recovery a year or so out. So we are not in that situation. We are not close to violating covenants. So that motivation really isn't there. And as Cary said we like have the insurance in place. The insurance is asymmetric in tis protection. You need it worse on the way down. You can afford to give up some of the upside on way up.

Cary D. Brown

And I want to say we’re continuing to watch it, and our decision if the back end of that curve start falling clearly dramatically, we might change our view right now, it doesn’t look like that’s in our best interest.

Michael Blum – Wachovia Securities

Thanks gentlemen.

Steven H. Pruett

Thank you Michael.

Operator

We will go next to Ethan Bellamy with Wunderlich Securities.

Ethan Bellamy – Wunderlich Securities

Hello guys.

Steven H. Pruett

Hello Ethan.

Ethan Bellamy – Wunderlich Securities

Could you update me on the natural decline rate of the wells on a weighted average basis?

Steven H. Pruett

Ethan, we’ve always said the nature of our properties are 7% to 10% type of natural decline in some areas like the Texas Panhandle where you have an old depleted reservoir, 3% or 5% decline. In other areas with natural gas particularly it’s about 10% but the weighted average when you put all the different types of PDP properties that we have up to the 7% to 10% range.

Cary D. Brown

You might see a little higher than that in this both third and fourth quarter where we drilled significantly, so that natural decline in Q1, Q2 may be a little higher than what it will level out at but that 7% to 8% was going to level at it.

Steven H. Pruett

Yeah it’s a great point. Cary speaking to the Wolfcamp drilling we did or Wolfberry drilling we did in the fourth quarter and the Pullman-Moscow drilling behaves on a hyperbolic decline of wells coming in at 100 to 400 barrels a day and they declined rather steeply in the first couple of years of the their life and settle out to produce that low decline rates for very long-time. So the $25 million that we invested in second half of this year will change the near-term decline rate but the long-term decline rate of our base properties, if you just turn off CapEx, is more in the range of what I described.

Ethan Bellamy – Wunderlich Securities

Okay and on the $20 million to keep production flat what’s the inventory look like there? Can you do that for the following year as well? At some point that seems like that number would have to go up?

Steven H. Pruett

Let’s turn it to Paul’s addressed that because he runs that business day-to-day.

Paul T. Horne

It depends on how you answer the question. From a reserve report perspective, you absolutely run out of opportunity, those kinds of opportunities for two reasons. One is that practice have cut off a number of those opportunities, but more importantly as you do that kind of work it leads to additional opportunities and additional work that you learn is, successful ways you do it and so we've on the books we show a pretty solid and always have a three year kind of number to be able to do that, but at the end of next year we will show a pretty solid three year kind of number just like we did at the end of 2006.

Cary D. Brown

It give me great confidence what Paul said and his team is that every year we substitute an high grade our project inventory so that the projects that are on our reserve books many of them get deferred into subsequent years because of our engineers find opportunities in existing well bores, we act on those within a budget cycle they never appear on our reserve report till they turn up as an improved PDP property, it also gives me encouragement that properties of Kyle McGraw and our predecessors operated back into the 80s, we're still finding opportunities on those fields and improving production on fields that are 60 years old and that have been in the, our family portfolio so to speak since the 80. So, it seems that our engineers are, and we've had new engineers look like old properties and been able to bring in new properties that other companies have look at and find hidden treasures. We will pay attention to what offset operators are doing and they've opened up some new opportunities for us and. So, we are very encouraged, our inventory on our reserve books is not reflective of the opportunities we have, and example is, we have over 240 acre infill locations in our Spraberry and Wolfcamp asset if you will that we haven't booked, and that would take an awfully long time for us to drill companies like will half way long time for us to drill companies like Pioneer have those 40 acre infills on their books or they've already drilled a lot of them. We haven't because we have higher return opportunities in our investment portfolio that out rank those and get drilled and acted upon first and those will be therefore for years to come.

Steven H. Pruett

I am still focusing to this Cary is, is that if you are asking is if what we are trying accomplish is spend about 20% of our EBITDA, we did at year in, year out and find good projects to do, if you were to take this asset base and say, hey that's been a 100% of our EBITDA on it. You might run out sooner than that but and start having to find another things do but we think that at 20% level we can do that year in, year out.

Ethan Bellamy – Wunderlich Securities

Okay. I appreciate that. For your CapEx budget is that NYMEX prices you are looking for is that realized prices with the 15.5?

Cary D. Brown

Well, those are NYMEX prices so realized is half of that somewhat.

Ethan Bellamy – Wunderlich Securities

Okay.

Cary D. Brown

Now they're $3.

Steven H. Pruett

Ethan those are hard numbers.

Ethan Bellamy – Wunderlich Securities

Okay.

Steven H. Pruett

Those are number we are going to look at and we are going to do what make sense they are just less things that makes sense at lower prices.

Ethan Bellamy – Wunderlich Securities

Sure. Okay last question and then I will let somebody else jump in. I know it's not relevant until 2011, but did a potential tax changes that Obama has proposed does that impact you guys at all, could you talk a little bit about that please?

Steven H. Pruett

I will pop off and [turn] this to Cary again.

Cary D. Brown

Sure it looks to me like he is trying to drive up prices as high as he get them in, if he actually does pass, what he is talking about passing own and PDP production is going to be a great place to be. Now, they will affect us in, not being able to use up IDC is going to be a problem, but in the short term they are going to do some really interesting things so the drilling world and those of us who are producing PDP will be able to watch the price just continue to go up. That's what it looks like to me, it will definitely impact us it will impact us less than Sea Corp. that spends dollars revenue drilling.

Steven H. Pruett

Ethan why I’d say is it could be before 2011. Cary came in this morning I have been alarmed by the administration stance toward the oil industry a month now. You know guys this could happen sooner than we thought it could happen as early as April 1. But let me say that with regard to Legacy's tax shield, we have not been able to absorb all of our IDCs we have an up cost depletion which while the statutory or fixed percentage depletion is being discussed as a possible victim of Democrat's pen. On the other hand the ability to pass through depletion as we typically do in units of production won't go away. We will be able to and because we have such a good cost basis from our formation transaction that stepped up the basis of our assets. We've been able to provide a 100% tax shield every year, we believe that's the case this year, and we've not been able to absorb all of our IDCs, which is to say. We still have a good tax shield. We've been having deferred IDCs so we are kind somewhat in the same boat that we were before. Everything is going to affect this in some ways because that is favorably from the standpoint of, there will be further degradation in the rig count, which will further diminish gas supplies, which hopefully will get our gas market rebalanced, and give us quicker recovery in that gas prices. It doesn’t feel very good having a target on our backs, but on the same token it will just be disrupted to development of secured domestic oil and gas supplies.

Ethan Bellamy – Wunderlich Securities

I understood. I appreciate that guys hanging there.

Cary D. Brown

All right. Thanks a lot Ethan.

Operator

(Operator Instructions) And we will go next to Pavel Molchanov with Raymond James.

Pavel Molchanov – Raymond James

Hi, guys.

Cary D. Brown

Hello Pavel.

Pavel Molchanov – Raymond James

Question about distribution coverage back in the good old days I remember you guys use to target I think it was 1.2 or 1.3 times coverage over the intermediate term, under the new commodity environment, can you give us your thoughts on where you think that number should be?

Steven H. Pruett

At our birth, well, you may remember we were actually below 1.1 at not our birth at our IPOs. So, we had to build coverage overtime we were able to do that through acquisition so every time we acquired something, we're able to build up a little question, and we have 1.6 times in the first half of the year which was a wonderful thing, but 1.2 has been more of our target and whether we are able to cover that is entirely driven by where commodity prices are quite frankly we'd like to see life in the 1.2 range, it doesn't look achievable this year unless it's driven by reducing this distributions to further drive down our debt balance.

Pavel Molchanov – Raymond James

I understood.

Cary D. Brown

The coverage ratio today to me is not a driver in how you make distribution decisions it is the balance sheet and making sure that your balance sheet in a good shape, and that’s going to be more I think you're going to see more and more that it doesn't appear that the market is rewarding significant distributions they are rewarding safety more than they are rewarding a high distribution that may change in the future, but I think that the market is looking for safety not high distributions. So that may color how we look at distributions in the future.

Pavel Molchanov – Raymond James

Understood. Are the banks, in your consortium giving you any guidance or any observations on where they would prefer coverage to be?

Steven H. Pruett

No they really aren’t, I think the main thing Pavel they are, they were very encouraged by the distribution announcement on January 20th when we said we would review our distribution policy in order to maintain financial flexibility and that was related to uncertain and volatile commodity price environment and tight price capital markets and we are encouraged that we are going to be proactive about managing our liquidity and availability and not lean on them or not wait for them to tell us when that's appropriate. So, they are not providing any type of guidance or advice on where our coverage should be. They just want to know that we are going to we know their borrowing base models, and that we're going to stay ahead of them. And that we're also in tune with their needs on rising costs of capital and a competitive market clearing fee structure as well.

Pavel Molchanov – Raymond James

I got it thanks guys.

Cary D. Brown

It seems like the banks are telling us with a full year hedge position, we're the least of their concerns.

Operator

And we will take a follow up from John Kang with RBC Capital Markets.

John Kang – RBC Capital Markets

Hi. Just a quick question on LOE. I guess, in previous quarters, you had commented on high LOE expenses due to, buying new acquisitions and having to go and spend extra on workovers and the like. I was just wondering for the fourth quarter can you, if its possible can you break out, were there just better just better acquisitions that you made and you didn't have to spend that excess amount on the new properties, or was it more attributable to, just lower costs. Just to get a sense for the future for LOE for you guys?

Paul T. Horne

John this is Paul Horne. I will respond to that. We saw a reduction, I believe, of about $5.50 per Boe, and we calculated somewhere in the $2 range of that was due to a reduction in our workover cost. Some of that workover is exactly the monies you're talking about is the monies that we spent on acquisitions that we made in the second and third quarter, and then some of that is strictly discretionary workover monies, that we were spending on properties that we've had in the past. So, I think what you're seeing there is, is not quite half maybe a third to 40% of that decrease from Q3 to Q4 was in a reduction in workovers and the balance being roughly 60% from a decrease in the cost of goods and services. We did not see any acquisitions that we made late third quarter, early fourth quarter we did not see significant issues that needed a high-spend rate to bring those properties up to appropriate standards be it mechanical integrity standards, environmental standards or any other issues that we saw there. So, it was probably a combination of that.

John Kang – RBC Capital Markets

Okay great thank you.

Operator

And we will go next to Yves Siegel with Aroya Capital.

Yves Siegel – Aroya Capital

Good afternoon guys.

Cary D. Brown

Hi Yves.

Steven H. Pruett

Hi Yves. Good to hear from you.

Yves Siegel – Aroya Capital

Thank you. I just wanted some clarification, as it relates to balancing acquisition opportunities, liquidity and the distribution, I am just not sure if what you were saying before was that if there was a really good acquisition opportunity you may decide to or you may recommend to the Board to reduce the distribution to help the liquidity out. So, could you once again just address that for me?

Steven H. Pruett

You are talking, there was, I talked a little bit about the CapEx that we had, we get 20 million of CapEx budgeted on that I think would be easily usable for an acquisition as opposed to drilling wells or doing something else.

Yves Siegel – Aroya Capital

Okay.

Cary D. Brown

So, you are looking at that, that's a possibility in this market and then in terms of going out and financing an acquisition, Ethan, we're are looking at all kinds of things, look at that piece.

Yves Siegel – Aroya Capital

Yeah.

Steven H. Pruett

So, we made the linkage of cutting distributions to fund the acquisitions it was really first cutting CapEx to improve liquidity and improve the return on our invested capital, two, if needed to go the next layer it would be possible….

Yves Siegel – Aroya Capital

Okay.

Steven H. Pruett

To cut distributions to further improve our liquidity and Cary was thinking only commenting on substituting some of our CapEx within it would be a small and it would have to be very, very accretive and strategic.

Yves Siegel – Aroya Capital

Okay.

Cary D. Brown

But I'd also comment Ethan, if we did choose in this environment to pay down some debt, then when the environment gets better, we are going to have a balance sheet that's going to look good and we won't have to raise equity to make additional acquisitions.

Yves Siegel – Aroya Capital

All right guys. Thanks for the clarification and Cary you can call me Ethan anytime you like.

Cary D. Brown

I’m sorry, sorry about that.

Steven H. Pruett

He is not as young and handsome as Ethan.

Yves Siegel – Aroya Capital

There you go. All right thank you.

Operator

We will go next to Richard Roy at Citi.

Richard Roy – Citibank

Good afternoon.

Cary D. Brown

Hi, Richard.

Richard Roy – Citibank

Just on the borrowing base determination assuming that the borrowing base gets reduced to amount, where you have to reduce that, would you provide an outline or debt reduction plan or simply maybe a level of debt that you would be comfortable with?

Steven H. Pruett

Richard, if you are asking if we would have a plan provided by the banks or would we publish a plan?

Richard Roy – Citibank

No, would you outline, would you publish a plan saying this is what would happen with the borrowing base determination and this is our plan going forward?

Steven H. Pruett

That we would do that, because it will really be a subjective, it will be an analytical exercise on our part, based on an assumption derived from conversations of multiple banks on where their price forecast and outlook is and where they think it's going, and an assessment of their ability to lend money that would drive us to such a decision. So, it would be something that's not crystal clear. It's somewhat of a crystal ball exercise of three to four months ahead of time and I think to more precise on a plan, would be overstating our ability to predict exactly where the banks will be. But what we do know is that we don't want to wake up on October 1 and be overdrawn so to speak or fully drawn or close to fully drawn, and so I think publishing a plan would be maybe a little presumptuous service. And I wouldn’t want to let our banks off the hook so to speak with what we think they should be able to provide in the next borrowing base. We don't want to sort of have a fulfill our destiny by publishing a plan that says, hey they're going to reduce two x and then sort of set the target for the banks, we want them to continue to work with us and help us with managing the liquidity in our business. In terms of giving us some fair market borrowing base, so we've got the October 1 to look forward to and then April 1 of 2010 is the next one after that as you know, we…

Richard Roy – Citibank

Right.

Steven H. Pruett

We re-determine twice a year. And our expectation is we will see some improvement in the economy and hopefully commodity prices by the time April 1, 2010 rolls around that really, our – we think our weak points and so to the bottom will be October 1, 2009.

Richard Roy – Citibank

But there is no I guess percentage drawn that you would look for because I guess the determination could be relative to what the bank or what do you expect the banks to say, you are going to determine how much you need to reduce debt. So, you have a target percentage drawn that you would like to abide by generally speaking or not?

Steven H. Pruett

Well, we like to stable at 90%, but as we’ve said before we have the ability to pay our distributions with our hedges. So, while we have a covenant that precludes us from borrowing our last 10% of availability to fund distributions we can cash flow our distributions with our business plan as it is, even at lower prices. So, we can accumulate the cash over the quarter pay the distribution and move on to the next quarterly period do the same. So, that 90% given our business plan for 2009 isn’t a problem, but it feels a lot better to be below 90%. But it's not the, it's not a problem if we cross the 90% line, but prudent management would say you always want to leave availability in some level of liquidity on your borrowing base.

Cary D. Brown.

I don't want to come cross on this call is if we made the decision to do that it is we are continuing to look and continuing to evaluate the market and our model show we can continue to pay it through '08 distribution for the year of 2009. So, the Board haven't made, the Board haven't decided and we will look at it quarter-to-quarter and the environment we are in, if the environment improves dramatically within, and that changes the way banks are going to respond and the way we will respond if the environment gets appreciably worse then we look at that. So, no decision has been made, we haven't left anything. We just felt like it's important to tell the market that just because we can pay our distributions doesn't mean we will.

Richard Roy – Citibank

Very good. Thank you.

Steven H. Pruett

Richard, I would add to that. We've got another 48 days before our Board meets to determine our distribution, so that’s in this volatile market that seems like a long time away that will be here before we know it, but we will be collecting information in terms of the commodity markets the cost and the strength of our bank group over that timeframe and the outlook of our bank group to help us make that decision at that point.

Richard Roy – Citibank

Great. Thank you.

Steven H. Pruett

Thank you Richard.

Operator

And our final question today comes from [Steve Pfeiffer], Private Investor.

Steve Pfeiffer – Private Investor

Hi guys. How are you?

Steven H. Pruett

Steve, private investor. Good to hear from you again.

Steve Pfeiffer – Private Investor

I was going to ask on the production. it increased from the third quarter to the fourth quarter on the back of I guess from acquisitions and increased drilling what’s the outlook for the second quarter i.e., are some of the acquisitions that you made, is it going to full impact them in the first quarter will we see the production increase or what’s your outlook for Q1?

Cary D. Brown

Was spoken like a former petroleum engineering and oil analyst or equity analyst that you're. We have a fleet much of full quarter contribution from our acquisitions, but the drilling was ongoing through the end of the year and so we did not get a full quarter benefit from our Q4 CapEx, Paul would you add any color to how that’s going to play as we try in wells to sales.

Paul T. Horne

Yeah. I'm dancing a little bit on a thin ice of not giving guidance of yet giving some color to that answer, what I would say is we didn’t have a full quarter of impact from the CapEx we spent in Q4, but as Cary mentioned earlier, we also spent about $10 million of CapEx in Q3 and as you know when you drill that's a well, if we drill those wells come on at very higher rates and then have pretty high declines until the B factor kind of levels them out and causes them to go on a much more typical life long decline and so I think the Q4 production that we had online was offsetting the declines occurring from that Q3 production and I think you will see declines on that fourth quarter production in Q1 that will offset what increase as you might expect.

Cary D. Brown

We're not expecting substantial increases in the first quarter.

Steve Pfeiffer – Private Investor

Let me ask it this way, just broadly to be I guess, it's what you done on the $20 million capital program for maintenance on workovers and what not all things being equal that should keep you in sort of the steady state of production of call it $8,500 barrels a day is that fair.

[Multiple Speakers]

Cary D. Brown

That we weren't going to comment on one way or another, but we believe $20 million is adequate to hold production relatively flat.

Steve Pfeiffer – Private Investor

Great, thanks. And the other question I was going to actually go back to the borrowing base quite should, a little different way, and I am sure you guys and Steve you've analyzed it fixed ways to Sunday, but my question was, I guess, in November of 2008, borrowing base was at 410 and under the current pricing regime used by the banks, you feel reasonably comfortable that you won't have a problem that the borrowing base will be above your current outstanding balance. What kind of a, roughly speaking oil price and/or gas price do you need or would the banks need to use before you would start to get to where it could be below that $300 million outstanding balance.

Cary D. Brown

You know, Steve it's a dynamic question. You know, right now, we think the bank so the feedback we are getting and by the way our agent bank has recommended a specific borrowing base, but we don't want to got into our banks, at with it we haven't got any push back on that, but we are still a week or so away before we or couple of weeks away before we get all the commitments and, but and we don't think the borrowing base is driving the factor as much as the bank's ability to lend money on the terms that we have put out in the market, but by the time the falls rolls around and what is now maybe a $55 or $60 long-term bank price outlook and we are assuming $55 that could change and that's what really drives things and by that time, we will have had some roll-offs on both our hedges and our production. So, it changes the game a little bit, we have already done a roll-forward calculation to like a July 1 effective date and then as we look forward to the fall redetermination, we will do another role forward and so you have a depletion element to it you have cost that are continuing to come down and so there is really not a crisp answer that I can give you on it, certainly its well south of the $50, $55 long-term oil price outlook, they're having this ground, but certainly if they collapse to something like the lows in the recent market and held that flat for all time that will be a problem. But where we are today with the forward curve the banks as you know always mitigate the volatility and don't move up as fast as the market moves up nor do they move down as fast, because that's just not the way they manage their business and as Henry [Grady] said so well, the forward curve has been a horrible predictor of oil prices over time, and the banks are in gene with that not going to use the forward curve to dictate what their long-term outlooks are having said that the contango curve helps for now and we will see how long the banks use the contango shape to their price tag.

Steve Pfeiffer – Private Investor

Good. Thank you guys. I appreciate it.

Cary D. Brown

You bet Steve. Sorry, I wasn't as responsive as you might have liked.

Operator

And there are no more questions in the queue at this time. Mr. Pruett I would like to turn it back over to you for any additional or closing remarks.

Steven H. Pruett

Well, go ahead, Cary.

Cary D. Brown

I'll just say, I read today that Boone Pickens is predicting $75 oil by the end of the year and here, I'm hoping he is right and I'll tell you from management standpoint we're going to manage this company to succeed over the long-term even if it means, we take a few bumps along the way, and we don't see anything as management that would cause us concern over that may had some hard decisions, but that's why you pay us to make hard decisions and to do the right thing for the long-term We've got great banks they've been cooperative, they've been through a test cycle, but they stood there with us and I don't expect any long-term. There is a distribution cut, I don't expect it to stay for the long-term because I expect prices will recover and when prices recover we've got long-term good assets that are going to be around, to pay distributions for many years to come. So, with that I will Steve you're going….

Steven H. Pruett

I would just add we created Legacy in a $60 environment, of course our predecessors operated in environments around $10 a barrel and as good as $30 a barrel. We lived most of our life in the $20, $10 to $30 environment. So, we don't need a restoration to a $100 plus oil, I would also remind the investment community and the analyst that we do own the families represented on this call and Management and Directors own a little over 40% of the outstanding common units, the same form of units that you all have. And that creates a great alignment of interest. Most of our income is still on the form of our distributions. So, we care about the distributions, just as all of you do, but we also care about the sustainability and longevity of this model that we've created. So, we definitely appreciate your being with us alongside us and supporting us through this and very much appreciate the support of our banks through this tight credit crisis. And with that I think we'll sign off.

Cary D. Brown

Thanks guys.

Operator

And that does conclude today’s conference. We appreciate your participation. You may disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Legacy Reserves LP Q4 2008 Earnings Call Transcript
This Transcript
All Transcripts