Good morning. My name is Cynthia, and I’ll be your conference operator today. At this time, I would like to welcome everyone to the St. Mary Land & Exploration Company’s fourth quarter and full year 2008 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator instructions) Thank you. I would now like to turn today’s call over to Brent Collins, Director of Investor Relations. Please go ahead, sir.

Thank you, Cynthia. And good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company’s fourth quarter and full year 2008 earnings conference call. Before we start, I’d like to advise you that we will be making forward-looking statements during this call about our plans, expectations, and assumptions regarding our future performance. These statements involve risks, which may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the information about forward-looking statements in our press release from yesterday and the Risk Factors section from our 2008 Form 10-K, which we expect to file later today. We'll also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliations of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday. Additionally, we may use the terms probable, possible, and 3P reserves, and estimated ultimate recovery or EUR in this call. Probable reserves are unproved reserves, which are more likely than not to be recoverable. Possible reserves are less likely to be recoverable than probable reserves. Estimates of probable and possible reserves, which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain to estimates of proved reserves, and accordingly, are subject to substantially greater risks of not actually being realized by the company. EUR means those quantities of petroleum, which are estimated to be potentially recoverable from accumulation plus those quantities produced there from. We may also discuss proved reserve volumes calculated under different pricing assumptions than what is currently allowed in filings with the SEC. The company officials on the call this morning are Tony Best, President and Chief Executive Officer; Jay Ottoson, Executive Vice President and Chief Operating Officer; Wade Pursell, Executive VP and Chief Financial Officer; and Brent Collins, Director of Investor Relations. I’ll now turn the call over to Tony.

Good morning, everyone. And thank you for joining us this morning for our fourth quarter 2008 earnings conference call. Before turning the call over to Wade and Jay for their respective financial and operational reviews, I have a few opening remarks. 2008 was an interesting year, to say the least. As an industry, we saw commodity prices rocket to an all time high and then quickly retrenched as a result of the broader financial crisis. As a result of the weak commodity prices at year-end, many E&P companies saw meaningful negative price revisions to their proved reserves, which in many cases resulted in impairments or write down of assets. St. Mary was not immune to these industry developments, and our reported financial results reflect that for last year. Proved preserves for year-end 2008 decreased to 865.5 Bcf equivalent from 1 billion 86.5 Bcfe – excuse me, that’ll be 1 trillion 86.5 Bcfe in 2007. The decrease was largely a result of negative price and performance revisions that Jay will cover more in detail in his review. From a production standpoint, St. Mary had a strong year. We have record production of – in 2008 of a 114.6 Bcf equivalent, which is a 7% increase from last year. On adjusted board of divestitures of non-core properties, we grew 13% year-over-year. We also have a record quarterly production in the fourth quarter of 2008 of 30 Bcf equivalent or 326 million cubic feet equivalent per day. St. Mary’s a stronger company today than it was a year ago. First, we continue to execute on our strategy of transforming St. Mary into a resource plays leveraged company throughout 2008. Results of St. Mary’s development of the Woodford Shale and Wolfberry Tight Oil assets improved nicely during 2008. We also now have exposure to…

Thanks, Tony, and good morning. Yesterday, we released our quarterly earnings press release and financial highlights, which present our fourth quarter and full year results. I know it’s a busy time for many of you on the call so I’m going to focus my comments on key aspects of the fourth quarter. We reported a net loss for the quarter of $126 million or negative $2.01 per diluted share. Consistent with those in the industry, we have significant non-cash impairments in the fourth quarter that were triggered by the lower oil and gas prices in effect at the end of the year. Adjusted net income for the quarter was $27.1 million or $0.43 per diluted share. And last, but not the least, we provided a reconciliation of the adjusting items. Non-cash impairments were the largest reconciling item this quarter. Discretionary cash flow for the quarter was a $163.3 million or $2.61 per diluted share. Production for the fourth quarter was 30 Bcf equivalent, which was about our guidance of 28 to 29 Bcf equivalent. It was a quarterly record for it happening. Strong performance in the mid-time that was the principal cause for the out performance. Consistent with what you’re hearing from other E&Ps is wider differentials had an impact on our revenues. Since the beginning of 2007, our average pre-hedge realization for oil has been 94% of NYMEX. In the fourth quarter of 2008, it was only 85%. And it’s a similar story for gas. Since we reported our gas on a webcast convention and because we have a reasonably rich gas stream, we have historically realized a price very close to NYMEX gas. From the beginning of 2007, our average pre-hedge realization for natural gas has been 99% NYMEX. Clearly, higher prices for NGLs over the mentioned period…

Thank you, Wade. I’m going to spend a few minutes discussing our year-end proved reserve report. And then I’ll provide an update on our operations and plans for 2009. As reported on our operation’s press release from yesterday, our proved reserves from 2008 came in at 865.5 Bcfe, which is down 20% from the 1 trillion and 86.5 Bcfe at year-end 2007. The reserves that comprised that 51.4 million barrels of oil and 557.4 Bcf of natural gas and are 83% proved developed. Over 80% of St. Mary’s proved reserves by value were either reviewed or prepared by outside reserve engineering firms. Prices used to determine the proved reserves decreased significantly from 2007 to 2008. Base SEC mandated pricing and effect at December 31st, 2008 was $5.71 per million BT [ph] of gas and $44.60 per barrel of oil, which are down 16% and 54%, respectively, from the 680, and 95, 98 used on December 31st, 2007. In addition to the drop in base commodity prices used for the calculation of 2008’s preserves, the company was significantly impacted by larger differentials for oil and natural gas liquids on this measurement date. Proved reserves were adversely impacted by a negative pricing and performance revisions at year-end. St. Mary’s negative price revision for the year was 199.7 Bcfe, at which 74% related to proved developed reserves. In other words, a lot of these reserves are still producing and providing cash flow and what is being cut off is the tail of the decline curve. Two-thirds of the 199.7 Bcfe and negative price origins were from oil weighted properties in the Rockies, which bore the brunt of the reserve impact caused by a lower year-end oil price and a significantly wider price differential. Lower year-end prices for natural gas liquids also led to…

Thanks, Jay. Last night we also announced the pending retirement of our Chairman of the Board of Directors, Mark Hellerstein. He stepped down as CEO two years ago and continued serving as our Chairman. Mark has decided not to stand for re-election at our May stockholder’s meeting, and will step off the Board at that time. The Board thanks Mark for his many years of distinguished leadership, dedication, and service to St. Mary. During his tenure as CEO and Chairman of the Board, the company has delivered consistent performance and returns for its stockholders year-after-year with a culture and foundation of excellence and values on which the company can continue to build. It is a legacy of which Mark can be very proud, and we wish him all the best in the future. I mentioned in my opening remarks that St. Mary is a stronger company today than it was at the end of 2007. And I have every expectation that it will be a stronger company at the end of 2009. We have a strong balance sheet that we can use to weather this difficult period, along with the ability to capture select opportunities that may present themselves. Our plan is to invest within cash flow this year so that we can maintain our financial strength. With limited long term commitments for rigs and no meaningful lease expirations on the horizons on the near term, we have the ability to be very flexible. We can accelerate our activity should industry conditions improve, or we can slow down quickly should circumstances warrant. While we certainly think that 2009 will be a challenging year, our exposure to several emerging resource plays has the potential to provide meaningful growth and value for our stockholders and to significantly expand our drilling inventory to position us for long term success. With that, we’ll turn the call over for any of your questions.

(Operator instructions) We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Stephen Beck with Jefferies & Company. Stephen Beck – Jefferies & Company: Good morning.

Good morning, Stephen. Stephen Beck – Jefferies & Company: Just the first thing, I want to touch on the Marcellus. Have you identified where you’re going to drill those wells?

First two wells will be in McKinney County. Stephen Beck – Jefferies & Company: Okay. I assume they’re probably going to be verticals or have you decide that?

We’ll probably do power holes and go horizontal in both of them. Stephen Beck – Jefferies & Company: Okay. In the Haynesville, you mentioned that you had drilled three horizontals, first one’s Shelby County. Are you going to be – have you decided if you’re going to focus more on the status of – with the remaining two or is that going to back over at the Louisiana site?

Yes. The rest of the wells we’ll drill this year will be in East Texas. We need to test our acreage there and we have some expiring acreage. Stephen Beck – Jefferies & Company: Okay.

Stephen, that’s where our largest acreage position is, as well. We’ve got about 40,000 on the Texas side, about 10,000 on the Louisiana side. Stephen Beck – Jefferies & Company: Right. I remember that. Okay. That’s it for me for now.

Thank you.

Your next question comes from the line of Mike Scialla with Thomas Weisel Partners. Mike Scialla – Thomas Weisel Partners: Good morning, guys.

Hi, Mike. Mike Scialla – Thomas Weisel Partners: I have a question on South Texas. You talked about the Petro hot [ph] wells. You guys also have some non-operated wells in there. Can you say anything about those at this point?

Well, they’re operated by TXCO in a partnership with Anadarko. At this point, we haven’t released auto data about them. TXCO is the operator and we’ll let them talk about them at the point when the partnership can agree to release data. All I can really say at this point is that the results are fairly encouraging. Mike Scialla – Thomas Weisel Partners: Okay. Good. And then of the seven wells that you plan to retain, I guess by the end of February, can you give us any kind of break out on where those are going to be?

Seven rigs. Mike Scialla – Thomas Weisel Partners: Seven rigs, I’m sorry.

Seven rigs. Yes. Well, we pretty much have a full year rig in East Texas, drilling Haynesville wells. We’ll have a rig, probably, half a rig a year, one in South Texas drill in Eagle Ford and the Marcellus. So that’s another rig. We got a rig in the Rockies, up in the Bakken that’s under contract until the end of the year. We have a couple of rigs in Oklahoma, one in the Woodford that’s under contract until – for most of the year. And another one in Central Oklahoma, drilling Deep Springer wells. And we have a rig part a year in the Permian. So that pretty much adds up, I think, to the seven. We have some partial a year in various places that make that add up. Mike Scialla – Thomas Weisel Partners: Got it. Okay. And then, you said you’re going to have a rig in Bakken, are they going to be drilling Three Forks or where is it going to be? Is it going to be on the Bear Den acreage or where about?

Yes. We just finished a well in Bear Den and drilling another one. And we have some other wells planned. I think we’ll see how the year goes up there. I think if we have a – depending on how things go, we may try to take it and do some other things or kind of cut our exposure to some. Mike Scialla – Thomas Weisel Partners: Okay. I’ll get back in the queue. Thanks.

Thanks, Mike.

(Operator instructions) You’re next question comes from the line of John Healey [ph] with Force Investment Management [ph]. John Healey – Force Investment Management: Hi. Good morning.

Good morning, John. John Healey – Force Investment Management: You said you were negotiating with banks about new revolver. Have you thought about what sort of borrowing date? I know it’s hard to project, but I know your current’s about $1.4 billion. You were just using a line of 500. DO you have any idea what your – can you disclose what you’re looking at the structure there?

I probably can’t say too much. I will say that yes, our current base was $1.1 billion, October. Clearly, with the reserves and the prices being lowered it’s going to come down from that, but it’s – we’re pretty careful it’s going to be well about the $500 million commitment that’s there now. So we’re just getting in the early days of starting that process. We may try to increase the commitment. We’ll see how the back advertises and when will the terms apply. John Healey – Force Investment Management: Got you. And then thank you. And then just another credit question, on your statement of cash flows, you had a cash use of $47 million to accounts payable and accrued expense. Can you tell me what the hell is related to – I mean, why would that – such a big larger than normal cash use in the quarter.

Yes. That work tends to swing around quarter-to-quarter. And we had a – I can’t remember exactly what it was, but we have a big – I don’t know. We just tend to pay a lot of our bills closure to the end of the quarter. And they build up at the end of 930. It’s the only way– John Healey – Force Investment Management: Right. Right. Okay. And I’ll just have one more then I’ll get back on the queue. Has your hedging change much from your presentation last month?

No. I will tell you, the answer is no. The positions that you saw on the last slide are the ones that we still have in placed. And if you look at our PDP profile looking forward, on equivalent basis we have about 56% hedge in 2009 and then 45% hedge in ’10. And we actually have 36% of our PDPs right now hedge in 2011. John Healey – Force Investment Management: Got you. Okay. Thank you very much.

Thank you.

Thanks, John.

Your next question comes from the line of Mike Scialla with Thomas Weisel Partners.

Welcome back, Mike. Mike Scialla – Thomas Weisel Partners: Tony, yes. I’m back in the queue quicker than I thought. But could you elaborate a little bit on the Haynesville. You said you’ve been waiting on profit names. You were going to go with the ridged coated sand rather than ceramics. And people seemed to be told on one or the other. Can you just give us your thoughts on that?

Well, yes. We we’re – originally our plan going forward and we had allocated and had some store with some 20 to 40 box site. And after talking to all the other guys in the neighborhood and talking to our co-owners and looking it with other people we’re doing. The information we have is that there were a number of people pumping a larger box site that we’re screening out some of their fracs. And so we talked at length to our co-owners and other people, service companies. And we went to a smaller propionates of 40 to 70 premium resin coated sand. Still has a fairly high some inter-medium strength providence some kind of a 10,000 pound crash link. And that’s what most everybody out there is using now because, apparently, there have been some screen outs on the larger materials. So we changed prop. And, when we did that, we lost – we missed our frac date, which was supposed to be early February, and ended up taking a month delay. I guess our view of that was better to be right than – than quick. Especially in this environment. So we’ll be pumping – we’re actually setting up. I have some pictures, actually, of our setup. We’ll be pumping here should be March 9th. We have first frac day. Mike Scialla – Thomas Weisel Partners: Okay. In the Wolfberry – any update on the 40 acre spacing there? It looks like you may have booked some 40 acre wells. Is that correct in that play?

Yes. The 40 acres in the southern part of the field, in particular, have done very, very well. They look a lot like the parent wells. The economics are pretty good. At this point, our approach to the – to Wolfberry is that we think costs are coming down quickly. And in the Permian and – again, it’s our view that the right thing to do right now is to defer. Wait for lower costs. And so, we’re planning to – we have one rig around there right now. We’ll probably lay that rig down here after its commitment is up and come back to that when we think costs are bottomed. But, in terms of reserves, I think we had a very good year there. And the 40s look pretty good to us. So. Mike Scialla – Thomas Weisel Partners: Okay. In the Marcellus you mentioned the two wells you planned there. What kind of commitments do you have? And what do you need to do to satisfy the terms to earn the 43,000 net acres?

In fact, we don’t have to do anything ‘til next year. We could defer all our spending into 2010 if we want to or need to. We’d like to get a couple drilled this year in order to be able to understand our position better and be able to make good decisions about potentially expanding our position. But, I think, our total commitment is about $15 million but – and none of it has to be spent. It has to be done by the end of 2010. So we have some time. Mike Scialla – Thomas Weisel Partners: Has there been much activity in either McKean or Potter County?

Yes. There’s a number of wells that have been drilled up in there. It’s a little off the beaten path from, say the Susquehanna area or the southwestern area of Pennsylvania. There are a number of reasons for that. We did quite a bit of work before we entered there. We feel pretty comfortable that it’s a prospective. It is an exploration play and there isn’t a ton of production in that area deep. There’s not a lot of deep penetrations in Pennsylvania in general. But we feel pretty good about it. Mike Scialla – Thomas Weisel Partners: And then I wanted to go back to one more on the Bakken? Have you seen any improvement in the oil price differentials in North Dakota?

You bet. And, in fact, I think from year-end we’re already down about $5. I think year-end number in the Bakken was about $17. Now we’re down to about $12. I think, if you look forward, Enbridge is talking to – is talking about their expansions next year. Which should add a 40,000 to 50,000 barrels of capacity. So, I think, over time our view is that the differential’s going to get better. I think right now what’s really driving activity up there is just – just low oil prices. It’s just when you take $40 oil and stick $12 on it, it’s just not a good economic situation. And you are seeing rig count – finally starting to see rig count really falling in North Dakota. Mike Scialla – Thomas Weisel Partners: If oil prices do – say, don’t get much better than say $45 what kind of cost reduction would you need to see? Or would there be enough cost reduction to entice you to want to drill more up there?

Well, I think eventually there will be enough cost reduction to drill up there if oil sticks at these prices. I haven’t done a calculation on how low it’s going to get. I can tell you that to start drilling again at these differentials we would probably need to see $60 oil. Mike Scialla – Thomas Weisel Partners: Okay. And the Woodford, I think, on the last call you talked about some down spacing there and you were going to do some simul-fracs. Any results there?

Well we haven’t pumped our simul-fracs yet. We’re just getting all the wells drilled in the one section to be able to do that. And so we don’t have any results to talk about there yet. Mike Scialla – Thomas Weisel Partners: And the well costs there are still $4 million to $5.5 million or are you seeing any improvement there?

Well, I think they’re tending down below the fives now. And even the deeper part of the play. We see AFEs from other people that are still above fives – high fives. But most of our stuff is five or – is in that five range now.

We’ve been able to obtain additional discounts from several service providers in the mid-continent, Mike. So we continue to see the cross-trending down. And certainly, that trend will continue. Mike Scialla – Thomas Weisel Partners: Okay. One last one. I may have missed it in your release but do you have a pre-tax PD-10 number?

Yes, Mike. It’s Brent. It’s $1.3 billion. Mike Scialla – Thomas Weisel Partners: $1.3 billion is the one that’s based on – on the–

Yes. PD-10 based on SEC pricing.

Year-end pricing.

And year-end differentials. Mike Scialla – Thomas Weisel Partners: Do you happen to have any sensitivity on, say, a higher oil price?

No. We don’t have that. Mike Scialla – Thomas Weisel Partners: Okay. Appreciate it kindly. Thank you very much.

Thanks, Mike.

So our next question comes from the line of Joe Magner with Tristone.

Good morning, Joe. Joe Magner – Tristone: Good morning. Just a few questions here. The production outlook for the year is down from what would be the preliminary estimate you put out a couple of months ago. CapEx isn’t down – is down slightly from where it was at that point in time. Could you address some of the changes? I know you’ve talked about deferring development activity until costs come back in line. But just discuss some of the changes over the last couple of months and then, also, just some of the trade offs that you’re weighing as we look at the Q – the 2009 quarterly progression. It could be down in the order of 18% to 20% by the time we get to the fourth quarter. And just some of the trade offs between near term development activity, costs, prices, and your willingness or desire and need to test some of these new emerging plays.

Yes. We can address the – the difference in rate from the numbers in December is largely driven by the fact that we sold or traded the Judge Digby asset at the very end of the year; which is a couple of BCF for the year. There is a little less Woodford development in our current plan. We shifted some of that money around toward exploration. Just based on how we see the economics and the potential for lower cost in the Woodford toward the end of the year. So that – that really explains the differences. The CapEx is a little bit lower but it’s really Digby, smaller CapEx, and a little bit of reallocation that gets us to the new production number. What we’re showing is a production – we haven’t guided production every quarter. We’ve shown you a full year number. Clearly, we do expect production to decrease sequentially each quarter as a result of the fact that we’re just not spending near as much money as we did last year. So you can expect to see the numbers go down every quarter.

Joe, having said that, obviously, we’re going to be doing exploration work in our key emerging plays. And with success in those plays, and depending on the financial markets at the time, certainly we – we have the opportunity to ramp up if the situation warrants. Joe Magner – Tristone: Okay. Along the lines of development costs or needing to see development costs coming down in order to pick activity back up again, you talked a little bit about the Bakken. But what have you seen so far? What do you need to see in terms of costs across deflation in order to get more comfortable with the economic outlook of some of the various plays?

I don’t know that there’s an absolute level of cost that we’re looking for. It’s really more a function of what’s the trajectory of costs. In our view, right now the trajectory of cost is still sharply downward. Sharply deflationary. As long as you can continue to believe that costs are going to go down by another 20% in six months, then the answer is to defer. And we’re seeing significant – we’ve seen significant reductions in rig rates already. We think we’ll see significant reductions in a lot of other areas; the service costs that are also important. Rig rate is only 20% of the cost of drilling oil. But that’s the first thing that happens is rig rates start to fall. So really it’s not a question so much to us of absolute levels of cost as it is to when – when do we think that the costs have stopped dropping so fast. Because that’s what really drives a deferral decision. Joe Magner – Tristone: It sounds like some service companies or most service companies are willing to work with operators on some of the various aspects of their programs. Is there – have there been opportunities? Have you seen opportunities or had opportunities to sit down with these guys and – and negotiate some of that stuff? Or are you just waiting for cost to keep falling and then you’ll revisit and have discussions later in the year and once that starts to stabilize?

Typically, when you get into these cycles, there’s a game that’s played between the service companies and the – and the oil companies. The service companies want you to sign up long term deals and soon as – and they’ll cut the price a little and then ask you to sign up for a long term deal. On the other side of the table, when prices are going up they want you to sign a short term deals and pay more and more. So you say negotiate. Yes. We negotiate all the time with these guys. On every job or on longer term deals. But everybody’s waiting to see what happens with price. If it starts to come back up, obviously, the more leverage shifts to the – to the service companies. We have been told repeatedly by the major service companies that they all want to hold on to their people. That they’re all going to be aggressive in trying to earn work. I think those are – those are things worth counting on. But, until you – until you let this thing shake out, you are not going to see the best pricing that you can get.

Joe, one of the things we’ve done over the last year or so is we’ve created the position of a supply chain manager. And that individual has been successful in terms of aggregating the spend for St. Mary and using that to leverage better pricing with our various service providers. And he does that on a day in, day out basis. Whether it’s pipe, pumping services, frac sand. He’s done an excellent job in terms of working that to our benefit. Joe Magner – Tristone: Tony, you’ve indicated a desire since you’ve been there to expand the inventory of the company. From the two to three year length out to five years plus. Realizing there are some shifts in ’08, where do you think you are now? And where do you think you could be coming out of ’09 if some of these new emerging plays get off the ground and you start to see some success?

Joe, this is the best I’ve felt and most confident I’ve felt since we’ve been here. We really see the inventory beginning to grow dramatically. And with success, could grow even more significantly for the company. You’ve seen us continue to optimize our portfolio with the sales and divestiture of some of our non-strategic properties. But, as I take a look at the progress we’ve made in 2008, especially with the Woodford, dramatic turn around with that program. The EORs have more than doubled. The cost continues to be very competitive in the area. Then we had very good success, as Jay talked about earlier, with our 40 acre testing in the Wolfberry. So right there alone that was our two resources plays that have developed very well for us. And, as the market recovers, certainly we would like to ramp those up. But then what I’m really excited about are the emerging resource plays that we’ve mentioned. And that’s why, even in a difficult market, we are going to invest over $80 million in those three emerging plays, in the Marcellus, the Haynesville, and the Eagle Ford. And we’ve got great running room in all three. And a year ago, those three weren’t even on our radar screen. And now, with success in those plays, it has tremendous opportunity to strengthen and grow our inventory. Joe Magner – Tristone: Okay. That’s all I have. Thank you.

Thanks, Joe.

At this time there are no further questions. I would like to turn the call back over to management for closing remarks.

Thanks again for joining us this morning and for your continued interest in St. Mary. We’re excited to see what 2009 holds in store, not only for our company, but for the industry. We certainly live in interesting times. And I think St. Mary is very well positioned with a strong balance sheet and exposure to some exciting resource plays in front of us. Thank you for joining us this morning. And goodbye.

Ladies and gentlemen, this concludes today’s conference call. You may now disconnect.