SM Energy Company (SM) Q3 2008 Earnings Report, Transcript and Summary

Good morning. My name is Britney and I'll be you conference operator today. At this time, I would like to welcome everyone to the Third Quarter 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. Mr. Brent Collins, you may begin the conference.

Thank you, Britney. Good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's third quarter of 2008 earnings conference call. Before we start, I would 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 the information about forward-looking statements in our press release from yesterday and the Risk Factors section of our 2007 Form 10-K/A. 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. Lastly, 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 than 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, that are estimated to be potentially recoverable from the accumulation plus those quantities produced there from The company officials on call the call this morning are Tony Best, President and Chief Executive Officer; Jay Ottoson, Executive Vice President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Mark Solomon, Controller; Matthew Purchase, Treasurer and Budget & Planning Director; and Brent Collins, Director of Investor Relations. I will now turn the call over to Tony.

Good morning and thank you for joining us this morning for our third quarter earnings conference call. Before turning the call over to Wade and Jay for their respective financial and operational reviews, I have a few opening remark I'd like to share. The third quarter was certainly a challenging quarter both for us and the E&P sector as well as the remaining of you on the call this morning. Declining commodity prices, hurricane disruptions and the financial turmoil have tested many companies in our sector. Our employee report at St. Mary is in solid shape in spite of these events. As you'll hear in a moment, we are well capitalized and have sufficient liquidity to meet our expected near-term needs. Consistent with what we have been saying all years, our expected 2008 exploration and development projects will be within our near cash flow. So you haven't heard St. Mary talk about pulling back capital investment or coming to the market for financing. As many of you who follow the company closely know, we have talked a while now that transforming the company being longer [ph] is an early mover and is focused on repeatable resource plays. In recent weeks, a competitor of ours got into the spotlight the Eagle Ford shale in South Texas with an announcement of a successful horizontal test. The Eagle Ford is a great example of how this shifts in strategy have taken note at St. Mary. As you'll recall, for second half of 2007 finance, we made two acquisitions in the Maverick Basin, targeting the Olmos shallow gas play. What we also know at the time was that the Basin had additional formations of interest including the Pearsol and Eagle Ford shale. We did our technical work early and have been building acquisition of the layer 12 months in the Eagle Ford shale through joint ventures and grass roots leasings. Today we have a potential capture position in the Eagle Ford that could be in excess of 200,000 net acres, 65% of which will operated by St. Mary. You should expect to see more of this in St. Mary. The early capture of new potential resources and more success in these emerging plays will add to our growing multiyear inventory of drilling projects. I will now turn the call over to new CFO, Wade Pursell. Wade, joined us in September and we're very glad to have him on board. Wade?

Thank you, Tony. Good morning everyone. Yesterday, we released our quarterly earnings press release and financial highlights, where you can review our quarterly and year-end results. I'm going to focus my remarks this morning on the results for the third quarter 2008. Production for the third quarter of 2008 was 27.7 Bcf equivalent, which was a slightly under our guidance of 28 to 29 Bcfe. We estimate that we lost about eight-tenths of Bcfe as a result of Hurricane Gustav and Ike, which would have produces a 28.5 Bcfe for the third quarter and came a little of our guidance range. Reported net income for the third quarter was $88 million or $1.40 per diluted share. Adjusted net income which adjusted for non-recurring and certain significant non-cash items was $75.4 million or $1.20 per diluted share, which was higher than the first call estimates. The significant adjustment this quarter was non-cash debt related to the change in the liability related to the net legacy NPP plans, bad debt expense resulting from the bankruptcy of SemGroup and the loss related the hurricanes. The after-tax deducts from reporting net income from the change in the NPP liability was $22.1 million or $0.35 per share and was the resulted of the decrease of the NPP liability between June 30th to September 30th due to a significant decrease in forecasted prices for oil and natural gas as of the end of the third quarter. The after-tax adjustment realized the SemGroup's bad debt expense was $4.2 million or $0.07 per share, let exposure to SemGroup through the purchases of the portion of crude oil prior to their bankruptcy for June and July production. As a result, we've recognized bad debt expense in both second and third quarters. We don't believe that we have any further bad debt exposure to SemGroup, and we continue to work on collecting the amounts at St. Mary. Consistent with prior practice, we adjusted for the impact of the hurricanes in the third quarter. The after-tax adjustment of $4.4 million for hurricanes reflects the loss we expect to incur after reinsurance reimbursements related to the remediation repairs salvaged and have made [ph] efforts related to our properties that were impacted by the storm. The specific property that were impacted were Vermilion 281, and our properties at Goat Island and Galveston Bay. The reserves end production associated with these properties are not material to the financial position of the company. Discretionary cash flow for the quarter was $193.3 million or $3.06 per diluted share. GAAP cash flow from operating activities for the quarter came in at $252 million. LOE for the quarter of a $1.57 per Mcf equivalent, which includes amounts for work over was slightly high than we had a guided for the quarter. The shortfall in production related to the hurricanes that pushed our current unit costs up slightly since there were fewer units production to offset fixed cost and LOE structure. For most of quarter, oil field supplies and services were in high demand which resulted in LOE costs being at the higher end of our expectations. And there was little relief in the cost of services that involved fuel costs. Transportation in the third quarter was $0.24 per Mcf equivalent. The increase year-over-year is being good and brought the change in asset competition and the associated transportation arrangements in the Gulf Coast and ArkLaTex region. While the transportation expense has been increasing as a result of these new transportation arrangements to natural gas price we realized at the outset, so we have been increasing the associated increased transportation costs. Production tax in the quarter was $0.81 per Mcf equivalent which was lower than we have guided for the quarter due to lower commodities prices being realized in the period. G&A for the third quarter 2008 was $0.87 per Mcf equivalent, which was above the guidance we've provided for quarter. Our G&A is largely comprised of fixed costs for the shortfall in production from the hurricanes with G&A on a rolling basis. Additionally parts of our G&A are tied to the profitability of the company which was higher than what has been forecasted at the time the guidance was provided. Year-over-year, we're seeing an increase in G&A on a per Mcf equivalent basis due primarily to increases in compensation-related costs and increased headcount and larger payments for the Mcfe. DD&A came in lower than we had guided to $2.6 per Mcfe due primarily related to curtailment in production and higher DD&A per unit depletion as a result of Hurricane Gustav and Ike. Our effective tax rate in the third quarter of 2008 was 36.8% which was in line with the guidance provided. Current taxes comprise 12% of our tax rates for the quarter. I'll spend a few moments discussing our financial position and liquidity situation. At the end of the third quarter we had $387.5 million in 3.5% convertible notes outstanding and $170 million drawn on our credit facility. Our debt-to-book cap ratio stood at 31%, the convertible notes have a very attractive cash coupon rate and do not have financial debts associated with them. Borrowings have been extraordinary, the first that these notes could be purchased is April of 2012. On October 1st, the borrowing base and our credit facility was re-determined by our bankers at an amount of $1.4 billion, secondarily elected to stay with our committed amount of $500 million at that times, which we believe is sufficient for near-term needs. By September 30th and October 28th, we had $170 million and $198 million drawn respectively. So you can see we have a fair amount going under the revolver. With a credit facility of the total debt at trailing 12-month EBITDA limitation and a minimum modified churn ratio multiple, at quarter end our debt to trailing EBITDA was 0.56 times, which is well within the limit of 3.5 times. The modified churn ratio was 1.77 which was well above the 1.0 times required for the credit facility. The bank visits comprises of 11 banks led by Wachovia-Wells Fargo, is going to be one apparently. We've had no issues drawn on our credit facility to-date. We feel that we're well capitalized and so has got some dry powder at our disposal. We expect to hedge inward in net liability position with all of our hedge counterparties as of September 30th which has been the case for most of 2008. As a result of lower forecasted commodity prices we've moved recently into a net asset position with the majority of our hedging counterparties actually have a total net hedge in assets. Of the two of our hedge counterparties are in the bank group with the revolving credit facility and that I might also add that the other two were participating banks in the first round of the capital purchases from the Fed and from the U.S. Treasury. We regularly view credit well doing it for hedge counterparties. Lastly, our Form 10-Q we filed with the SEC later today, in that you can find more detailed information on our financial standing liquidity and hedging positions. I'll will now turn the call over to Jay for operational updates.

Thank you, Wade. Companywide, we're currently earning 15 rig. I will brief, some of the areas where we're focusing making most of our capital investments. Tony has already mentioned our involvement in prospective shale plays in South Texas. In a joint venture with TXCO and Anadarko that we've discussed previously, four horizontal test have now been drilled and are at various stages of testing. Two of these wells of the horizontal reentry wells targeting the Eagle Ford shale, while the Pearsol integral was tested with one horizontal reentry and one horizontal gas-rich well. TXCO is the operator in the AV area and they released information on these four wells in their October 20th press release. So I will direct you to that for more details. We planned to draw our first St. Mary shale wells in South Texas outside of the JV area, I just discussed in the first quarter. As Tony noted, we have acquired a significant amount of acreage in the area. At this point, we think we've captured the most prospective acreage based on our geology models. And we'll have some production data points across the acreage in the first half of 2009. In each sectors, St. Mary is currently drilling it's first horizontal hand fill shale well, which is located in the De Soto Parish Louisiana in the Spider Field. The rig is currently taking core samples in the bossier and hand fill sections and is expected to kick off the horizontal lateral within the next two weeks. The well design cost for an approximately 4500 square horizontal lateral. The well should be completed early in January of 2009. We have 50,000 acres in Haynesville play and the first well is obviously an important step in our development plan. Results from our operated program horizontal Woodford shale program in Eastern Oklahoma continues to improve. Today the company has drilled and completed 24 wells that have meaningful production histories. The average estimated ultimate recoveries for the last 14 wells is 3.4 Bcfe. The foremost recent wells have preliminary EUR which are at or above that per-well average. The company has previously guided to a range of 2.7 to 3 Bcf for a typical horizontal liquid well. Our completed well cost in the play for 4000-plus lateral links varies from $4 million to $5.5 million depending on depth and number of completion stages. We currently have three rigs working in the play and are also participating in a number of similar operated wells. Our plans for the next several quarters includes simul-crackings in down state wells which is an important next step in that development. In Eastern McKenzie County, North Dakota St. Mary's has a rig contracted to start drilling Bakken and Three Forks well in our Bear Den prospect are in late November. As we previously announced, St. Mary recently acquired 6200 net acreage in Bear Den which brings our total acreage in that area to roughly 10,000 net acres. The area around Bear Den is over pressured relative to some other parts of the play and we are encouraged by recent preliminary operated wells as we participated in and around our acreage. After a number of delays, we do have result on three horizontal Bakken test wells we drilled earlier this year in the company's Powers Lake and Stillwater prospects on the Mountrail and Burke county line. Their current commodity prices baked the differentials in the costs. Our Bakken completion of results in that area do not indicate potential for acceptable economy. I should note that losses [ph] from first of these wells confirmed the presence of nice looking Three Forks section under the Bakken. Several of that operators have made good wealth in the Three Forks in that area and that will be our focus for that area going forward. Moving to our West Texas activities, during this year the company began testing the viability of 40-acre increased density of Wolfberry oil wells at Sweetie Peck in the Permian Basin. The program included 15 wells in three pilot areas. Early results from testing have been positive. Performance of these infill wells has been similar to the wells drilled on 80-acre spacing. At the time of the acquisition of the Sweetie Peck assets in late 2006, we did not place a large value on the 40-acre locations because we were uncertain how economic they might be. We are currently working on our capital budgeting plan for next year. Although we don't have any definite numbers to share with you today. I think it is fair to say that with the addition of Haynesville and South Texas shale drilling in our portfolio, we have a very excited inventory of opportunities to choose from in 2009. With that, I will turn back over to Tony.

Thank you, Jay. Yesterday we also updated guidance for the remainder of the year. Our expected production ranges for the year now stands at 112.5 to 113.5 Bcf equivalent and reflects the negative production impact for hurricanes Ike and Gustav. At the midpoint of this guidance range year-over-year production growth on retained properties will be 10%, based on our exploration and development budgets of $758 million which is near our expected cash flow for this year. As Jay mentioned, we are right in the middle of our planning process for 2009. What we can tell you is that we plan to have a program that will at hold in cash flow for next year. We'll talk to everyone in late December on our capital plan and production guidance for 2009. Financially, St. Mary is very strong at the moment. We have a fair amount of dry powder at our disposal and by a number of different metrics, we are conservatively levered. I am confident that we will weather the financial upheaval that the broad economy is currently working its way through. And as the storm passes, St. Mary will be well positioned by virtue of its improved inventory and strong financial position to grow significant value for our stockholders. With that, let's turn the call over for questions. Question And Answer

[Operator Instructions]. And your first question comes from Stephen Beck with Jefferies & Company. Your line is open. Stephen Beck - Jefferies & Company: Good morning.

Good morning, Steve. Stephen Beck - Jefferies & Company: I have a couple, can you talk of how many acres you have in the Powers Lake prospects?

I think between Powers Lake and Stillwater, we had about 25,000 acres. Stephen Beck - Jefferies & Company: Okay. Looking at... I haven't heard anything about Hanging Woman. Is there any update to Hanging Woman and tons that you had there?

No, not really. Stephen Beck - Jefferies & Company: Okay. And then, just last looking at the Haynesville the horizontal well. Can you talk, how we talked of the nearest horizontal and how far away that horizontal is looking from your current well?

There's number of wells that have been completed around. I don't have exact distance for you it's probably... I don't even want to expect the way. It's northern to southern Parish. So it's pretty close to a number of wells if you are probably looking at the map, there were a number of Southwestern verticals that we drilled in the area. So, we think it's a good area. Some of the core to play, we think it'll... it's a good slab to test. Stephen Beck - Jefferies & Company: Okay.That's it for me for now. Thanks.

Stephen on the Hanging Woman. I mean... I think it's important to mention that that is not material to our pool of plans and growth trajectory. We continue to produce the field and we've seen production uptick of about a million barrels or so for the year. But, going forward, I guess its not being material to our growth plan. Stephen Beck - Jefferies & Company: Sure, I understood. Thanks a lot.

Yes. Thank you.

[Operator Instructions] Your next question comes from the line of Jack Aydin with Keybanc Capital. Your line is open.

Hi Tony, hi Jay.

Good morning, Jack.

Good morning. How are you guys?

We are doing well. Thank you.

I just want to drill a little bit more in to the Eagle Ford prospect. I mean everybody knew that the formation was there. What makes it still attractive now and also you're hinting that there is some worker issue involved there. Could you a little bit elaborate little more on it what you see, what you... there?

Well, Jack we are probably not prepared to give a much of a talk about our geologic concept here because we still view it as a competitive play. The water issue, I am not familiar with what people are saying about it. I haven't heard that one. Again, I think we've probably reserved most of our comments here until we've got some wells here to talk about it.

Do you have any test.... did you test any well late yet or no?

Well, we tested the wells with TXCO which we, TXCO has already released on those. If you look they had a press release on October 20th when we talked about those.

Okay.

Jack, most of those announced steps were from TXCO and also the others that were announced by Petrohawk are reasonably closed proximity to our current acreage positions. I mean we think we are in a very good neighborhood, but quite frankly we are still going through a lot of the geologic work and in understanding what some of these operators have literally pointed as later tests results.

Okay. I guess obviously, I mean you saw Petrohawk's announcement. They talked about their geologic ideas. We don't disagree with them. I mean generally what they say is pretty much in conformance, we'll argue with the geology [ph] and rock properties.

So what is interesting to me is basically if they were interested in the play, why would they announce that play will... why wasn't acquire more acreage and wait for them for an announcement. That's what I am really partial to it.

Jack we have the same questions.

Okay.

And I am not sure why they would, I mean they've had their own priorities at the time.

Okay.

We certainly wouldn't we have said that.

Okay. Thanks for that guys. Well, at least I got what wanted to hear. Thanks.

All right Jack. Take care.

Your next question comes from Mike Scialla with Thomas Weisel Partners. Your line is open.

Hi guys.

Good morning, Mike.

In terms of your Woodford wells, the 14 that have the 3.4 Bcf EUR. You have got a pretty wide range of cost there $4 million to $5.5 million. What was the depth in general on those 14? Were those the deeper and are you seeing higher recoveries as you go deeper or I guess what I am trying to get at is as you move east in the play, what do you expect in terms of the EUR and the cost?

Yes, no questions that we should see it go steeper and the cost go up. I mean I have seen a -- 5.7 million in some of the play there and you agree with participating with a number of owners over there you guys well crossed well in excess to that. But $4 million is really over... probably where you see 9000 Bcfe kind of numbers. The $5.5 million is quite more like a 11. There is some of that is in the number of completion stations we are pumping as well. So it's not just completely depth. I haven't got the data to show a direct correlation between depth and EUR and that's something we will be talking with the guys about. We do believe that it's probably likely that EUR will go up at some of the higher depths. But there is enough scatter in the data right now and with that number of wells I don't think I can conclusively say that.

Is it fair to say that when we step 3.4 we can see more upside to... and the cost might be on the higher end of that range of the year?

Well I am not going to forecast upsides in the EUR. So I can tell you that the cost will definitely be on the upside... on the high side of that range.

Okay. Sweetie Peck is the 40s work over most of that area, can you talk about what the potential there might be and I know you had some issues with rigs over there a while ago. How is that situation looking?

I am going to take that in two pieces. First of all there is a 164 40s in the 3P for Sweetie Peck. We don't think all of those will drill out but I think a good shale for that and it is a nice addition and certainly something we will be focused on. In terms of the rig, I think there is a little bit of... when we talked a lot about rig issues last year we have kind of slowing up and down. But if you actually looked at how many wells we drill, we drilled exactly the number of wells we said we are going to drill in the plan. And some way or other in our communications of the rig issue that we are having people got the idea that we were having difficulty in slowing down or something. And in fact, we got exactly the number of wells drilled that we said we can drill in the plan. The rigs there right now are very stable. We got a pretty much neighbors rigs fleet there and they're doing a very good job for us. We will just see what happens here as price go down some. Obviously we are hoping cost down from as well. But the 40s that we drilled so far are going to be economic, if these prices follow we have to there.

Mike I think most of the good news due remembering well my last year's we ramping that program up and sorting through the better rigs in the basin. We have got very strong rigs fleet now, very good crews and as well as a St. Mary drilling group it is for the supervision for that program.

Okay, great thanks. And then just last one on the Bakken play, can you talk a little bit about what you are seeing in Bear Den area why you like that you mentioned some other wells are being drilled there, I think you said in terms of rates or anything else so that compares to say your northern acreage?

Well the Bakken area looks very good. We participated in 10 or 12 preliminary wells in that area, various wells are working interest and they have the real nice high IPs and pretty decent 10 day rates that you see in the average of the play. The area up north, the Burke Montreal we never did see the IP rates. The rest of play was spanned, it's over pressured like the Brad Baird [Ph] and partial area. It means a lot of water production as well. So, we just didn't get the kind of test that we think you need to support economy, certainly not at these prices. I guess the one point I'll continue to make is that, you guys need to be watching differentials in the Bakken. New oil coming out of the Bakken right now has got about a $20 off amount of mix differential. So, if you were near at $65 oil prices, you are talking about $43 net bags. So a lot of these margin levels there just in were... but were fairly looking at strip and looking at out best acreage and Bear Den have some very good numbers plus 600 barrel a day kind of IPs, a lot of the wells there. And we think that's going to be a very attractive area.

And in terms of the Three Forks potential on that northern acreage, you mentioned there a couple of wells that have been pretty good around you that...

Yes, Continental drilled the Olmos well just to offset our steward acreage IP at 1200 barrels a day in Three Forks. So there is some really good looking Three Forks stuff up there. We just haven't tested it yet. We will not pay but we get elected to complete the Bakken there. So, and I think what we'll be doing is going back and be looking at the Three Forks and trying to get some offset there.

Okay. Thank you.

You bet. Thanks Mike.

At this time there are no further questions.

All right. We certainly appreciate everyone joining us this morning. St. Mary had another very solid quarter, even with the hurricane impact. We continue to be a financially strong company with significant dry powder for our future opportunities. We have a growing inventory of significant resource plays that we are very excited about. And at this point, I am very pleased with the company's transformation and very excited about the opportunities in front of us. With that I would like to thank you all for joining us today.

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