SM Energy Co (SM) 2006 Q1 法說會逐字稿

Good morning.

My name is Tamara and I'll be your conference operator today.

At this time I'd like to welcome everyone to the St. Mary Land & Exploration first-quarter 2006 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).

Mr. Hanley, you may begin your conference.

Thank you, Tamara.

And good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's first-quarter 2006 earnings conference call.

Before we start I need to read the following statement.

Except for historical information statements made during this conference call, including information regarding the business of the Company, may be forward-looking statements.

These statements involve known and unknown risks which may cause the Company's actual results to differ materially from forecasted results.

These risks include such factors as uncertainties in cash flow and reserves; oil and gas operating risks; volatility of oil and gas natural gas prices; the need to replace reserves depleted by production; competition; and the potential impact of government regulations, litigation and environmental matters.

The Company officials on the call this morning are Mark Hellerstein, Chairman and Chief Executive Officer;

Tony Best, President and Chief Operating Officer;

Dave Honeyfield, Vice President and Chief Financial Officer;

Jerry [Hirschler], Director of Business Development;

Dennis [Zuvietta], Manager of Reservoir Engineering;

Brent [Collins], Director of Investor Relations; and myself, Bob Hanley, Vice President Investor Relations.

I'll now turn the call over to Mark.

Thank you, Bob.

I'm pleased to report earnings for the first quarter of 2006 were the second-highest in our history.

We continue to make progress on our more important plays while the overall environment continues to include a hypercompetitive acquisition market, cost inflation and shortages of services.

At the same time oil prices are in record territory while gas prices have softened as a result of high storage levels associated with the mild weather.

The two-year NYMEX strip remains high at 952 per MMBtu and 74.76 per barrel of oil.

Net income for the quarter ended March 31, '06 was $50.5 million or $0.76 per diluted share compared to $35.1 million or $0.54 per diluted share for the prior year's quarter.

Net cash provided by operating activities increased 40% to $129.2 million.

Production increased 6% to 22 BCfe.

The average realized price increased 27% to 861 per MCfe.

Unit costs increased for the year as lease operating expense including taxes increased $0.32 to $1.88 per MCfe.

DD&A including impairments increased $0.11 to $1.50 per MCfe.

And G&A expense increased $0.20 to $0.49 per MCfe.

LOE was higher than forecast due to cost inflation of 15% in the Rockies, higher workover costs associated with several older field acquired last year and more difficult winter operations.

Additionally, we incurred significant expense related to problematic workovers in the mid-continent and the Gulf Coast and increased property taxes in Texas related to higher reserve valuations.

Despite this our realized oil and gas prices grew -- or margins grew more rapidly than did oil and gas prices, increased 27% to $6.24 per MCfe on a cash basis.

At our last conference call we noted that basis differentials had increased in the Williston Basin.

We've seen several pipeline expansion projects being proposed over the last few months which should help the longer-term outlook in the next one and a half to two years.

We've also seen some improvement in the current markets as well.

The average wellhead differential for sweet crude in Montana and North Dakota has gone from $9.00 in March to approximately $5.50 in May.

For the first quarter the average wellhead realization before hedges was $56.98 for oil compared to a NYMEX of $63.48 or a differential of $6.50.

For gas the average differential including quality adjustments before hedges was $1.50.

We expect for the second quarter for the oil differential to be in the $6.50 to $7.50 range and for gas to be in the $0.60 to $0.70 range.

We saw significant increases in production in several areas.

At the Bakken Play daily production increased 75% from a year ago to 3600 barrels of equivalent per day.

At Northeast Mayfield production increased 22% to 23.8 million cubic feet equivalent a day.

The Paggi-Broussard No. 1 well increased 30% to 13.2 million a day and at Hanging Woman production increased 243% to 3.3 million equivalent a day.

In the Rockies there were ten successful completions with 100% success rate, two successful recompletions out of three attempts and 35 wells drilling or being completed at the end of the quarter.

In the Bakken Play we have participated in eight completions since the first of the year included in the Anvik 16-18H where we have a 66% interest with an IP of 320 barrels a day.

The Lyle Peterson 2-17H where we have 62% with an IP of 295 barrels a day and the Pleasant Valley 2-6H where we have 44% with an IP of 390 barrels a day.

The Bakken Play is on schedule with approximately 30 wells planned for 2006.

Although we have seen substantial service cost inflation from May of 2004 to April of 2006, completed well costs for the Bakken Play have risen only about 8 to 10% because drilling days have been reduced by 7.

Outside of the Bakken Play, since the beginning of the year we have participated in the completion or recompletion of 13 wells in the Northern Rockies, in the Madison, Red River and [Niskew].

In the Southern Rockies ten wells were completed with two dry holes for the year-to-date.

With gas prices softening we have nonconsented to four wells in the Wamsutter area and three at [Chipeta] wells which are in non-core areas in those areas.

We're experiencing some delays for operated wells at Wamsutter.

We have six to seven wells planned for this year that are subject to lease stipulations until after July and we haven't been able to secure a rig yet.

We have also postponed wells at Fourbear and Murphy Dome.

Therefore in the Southern Rockies our total operated well count will likely drop from 23 budgeted to 16 wells or less.

Nonoperated wells, however, have been on schedule.

At our Hanging Woman coalbed methane project we are generally very pleased with the well performance but a little disappointed in the timing of activity.

To date we've participated in drilling 261 wells of which 175 are now on production.

In 2006 we participated in the drilling of 55 wells and completed 48.

Last week we added 25 wells to production at River of which 19 are already flowing gas at a rate of 1.2 million cubic feet a day gross which is well ahead of what the engineering would have said.

We expect another 11 wells at [Boxelder] to come on production in mid May.

Current operated CBM production is 4.8 million cubic feet a day gross and 3.3 million a day net.

We have two to four deep horizontal wells planned for the this summer.

We initially forecast 200 wells to be drilled in 2006, but we are revising our forecast to 140 as roughly 60 wells planned at OW Ranch in Montana will be delayed to early 2007 due to a backlog at the Montana DEQ.

This together with the delays in the Southern Rockies will result in a reduction of our drilling budget from $500 million to $477 million.

In the ArkLaTex we had very good results.

At the Terryville Field the Colquitt No. 1 alternative location well where we have 60% working interest had an IP of 2.7 million cubic feet equivalent.

We have varying working interest in five sections where we now are identifying approximately 26 PUDs and a total of 42 3P undeveloped locations.

We expect EURs for these wells of 1.72 to 2 Bcf with completed well costs of $2.2 million.

We completed the [Hewitt] 10-1 at Spider where we have a 78% interest for 7.2 million equivalent a day after quarter end.

We are now moving out of Spider proper to the North where we do not yet have well control.

However, if we're successful we potentially could have up to 17 locations.

A typical Spider well as an EUR of 1.5 Bcf and cost $2.7 million.

We recompleted the [Caris] No. 9 where we have a 57% interest for 2.3 million a day at Box Church.

We completed the St. Mary No. 4 alternative location Weyerhaeuser at Driscoll where we have a 62% interest for 1.5 million a day.

The Elm Grove Plantation 19-2 well with a 19% interest IP for 1.6 million a day.

Since quarter end we've completed three additional wells at Elm Grove and seven are testing gas while waiting on final completion.

We have over 200 PUD locations at Elm Grove.

In the Gulf Coast at Judge Digby the Ivy Major No. 7 is now producing 50 million cubic feet a day and we recompleted the Major's 4 for 45 million cubic feet a day.

We have an 11.5% working interest in these wells.

The Major 6 is currently drilling.

In the mid-continent the Paggi-Broussard No. 1 where we have 40% interest continues to produce in the 35 million a day range and 1500 barrels of condensate after one and a half years.

We recently drilled an offset 3-D anomaly at the Paggi No. 2 which we've seen on log 96 feet of pay with greater than 18% porosity.

This well will be completed in June.

At this time we're not sure whether this is an acceleration well or whether we'll actually be accessing new reserves or a combination of the two.

We completed a well that I'll keep unnamed for competitive reasons where we have a 45% working interest for 5 million a day where we're still leasing.

The Flowers Trust 1- -- excuse me, in the Atoka Granite Wash play we completed six wells with an average IP of 2.6 million a day.

The Flowers Trust 135 where we have a 46% interest had an IP of 6.5 million cubic feet a day.

At Centrohoma we continue to advance our three plays.

We've increased our net acreage from 20,800 net acres to 25,600 net acres.

In the Cromwell we completed the Faire 3-5 and the Jason K 3-6 with P grades of 1.6 and 1.25 million cubic feet a day respectively.

We've now completed a total of five wells in the Cromwell which average 1.3 estimated ultimate recoveries per well.

We completed the Ryan Gaylor in the Woodford shale; two of the three stages of frac sanded out and the early production test rate was 750 million -- or thousand cubic feet a day with 18,000 barrels of load water to recover.

Our only other Woodford well, the Ann Bey 2-7, has an EUR of 1.2 Bcf.

We're currently completing the Colgate Lake in the Woodford Shale.

In addition to our operations update I'm very pleased to announce our hiring of Tony Best as President and COO.

Tony is here to day to observe our call.

From 2003 to 2006 he was President and CEO of Pure Resources, a wholly-owned subsidiary of Unocal and he managed all of the onshore U.S. operations.

Prior to that Tony worked at ARCO in a variety of positions including President of ARCO Permian, President of ARCO Latin America, field manager for Prudhoe Bay and vice president of external affairs for ARCO Alaska.

He has a BS in mechanical engineering from Texas A&M and an MS in engineering management from the University of Alaska.

In looking to replace Doug York as COO we also wanted to find someone who we expect will become CEO sometime in the first half of next year.

I had previously advised the Board that after 14 years with St. Mary I'd like at some point in the foreseeable future to be in a position to pursue other interests.

Assuming Tony's future appointment as CEO at the request of the Board I've agreed to remain as Chairman and in that capacity will continue to serve the Company.

In summary we're very pleased with this year's progress.

We continue to be in an excellent financial position.

Oil prices are high and our long-term outlook is positive.

The longer-term outlook for gas prices also remains very strong.

We had the second most profitable quarter in our history, had the most profitable first quarter in our history and production is up 6% from last year and flat to last quarter.

We have an outstanding inventory of prospects to be drilled with multiyear plays in the Bakken and Red River formations and the Williston Basin, Northeast Mayfield in the Anadarko basement, Elm Grove Field in North Louisiana, Centrohoma including the Cromwell, Woodford, Wapanuka in the Arkoma basin, Terryville in North Louisiana and the Hanging Woman Basin.

Our full-year production forecast remains unchanged at 96 to 98 Bcf equivalent.

With that we'll turn it over for questions.

(OPERATOR INSTRUCTIONS).

Larry Busnardo, Petrie Parkman.

In the Centrohoma field, can you just remind me again what the plan is for this year in each of the different areas in terms of the number of wells that are going to be drilled?

In total I think we have about 19 wells planned; we have two operated rigs running and we would expect at some point with positive results that we'd probably increase the number of rigs to three or four but that's where we are currently.

And we'll see all three of those plays being tested throughout the year.

When do you expect to have the results on that first Wapanuka test?

Quite frankly, we feel like we're early in the stage here and it's still a competitive environment and we prefer not to talk about it for awhile.

Okay.

The well that you mentioned that you had a 45% interest in and produced 5 million a day, I don't think you mentioned the name of it, but is that in the mid-continent region?

It's in the mid-continent region, and it's in the Anadarko.

Okay.

You just don't want to get more specific in terms of the field?

Exactly.

Okay.

And then lastly, just in regards to the Hanging Woman Play, did you say that 60 wells would be deferred to 2007?

Yes, those are the ones in the OW Ranch which is in the Montana side.

It's not on federal acreage, but just because of a backlog at the DEQ it looks like it will be in early '07 instead of than later '06.

Okay.

A little bit of frustration there just in terms of that?

Yes, we've actually done look backs in terms of the performance of the wells, both the ones earlier as well as currently, and we're very, very pleased with the well performance.

It's just the timing gets a little frustrating; it just takes a little bit longer than you wish it would.

Okay.

Just one more question.

It seems like to me in terms of basis differentials in the Rockies, you guys aren't being hit as much as some of these other companies, at least in terms of the wider differentials.

Can you talk about that a little bit, about what you guys are doing there to help you get your oil moved and to continue -- or not having to shut anything in or delays or anything along those lines?

Larry, this is Bob.

I think we're in the mix with everybody else, but the crude oil that goes east in that Clearbrook market, the differentials are less and it's for the sweet crude.

I think where you're seeing even the wider differentials are those that go south into the [Guernsey] market.

And then there's the question of the quality of the crude versus some of it is more sour and asphaltic and whatnot and there are bigger differentials there.

I don't think ours are -- we're working pretty hard to sell our oil at the best price and whatnot and we've had very little of it if -- hardly any of it shut in which I think is key.

But I think that the differentials we're seeing are probably fairly representative of that area and as far as it's going into the [Desarro] refinery in Mandan or into the Clearbrook market east.

And one of the things Bob mentioned, I think in terms of differentials the market is kind of the market.

I think where we have had the favorable treatment is the fact that we've been able to move all our oil and that is a result of our long-standing relationships.

Great, thanks a lot.

Michael Scialla, AG Edwards.

Morning, Mark.

Without getting too personal I'd just like to hear you discuss a little bit more about your decision to do something you've been contemplating I imagine for sometime and if you could just give us your thoughts on that?

Sure.

There's a book called the Tipping Point and you're never quite sure where that point occurs.

And for me, when Doug left I felt like I probably had a few years left just in the way I felt and also seeing my age and what I wanted to do in the future.

And so I felt it was appropriate to talk to the Board and let them know just so we would hire the right kind of person to fill Doug's spot.

And my goals, and I think some of the know that I have other passions outside of -- I enjoy performing and the negative of that is that it's hard to do that when you're working full-time.

And I've been fortunate enough to pretty much achieve way more than I've ever expected to be associated with a company that's been -- provided very, very top tier performance for its shareholders over a long period of time in a consistent manner.

Being one of the top companies in the United States for each of the last six years.

And quite frankly, I've done more than I ever thought I would and I'm in a position where I have the ability to pursue another passion and age is a bit of a part of it in that I -- unfortunately the performing side isn't a full-time thing either.

And so I would love to be on a few Boards.

And I think you can't let yourself get too old to do that because I think you get less attractive.

So I think this is sort of the right time.

And I may look back and say this is the craziest thing I ever did.

And unfortunately, once you make that decision you're going off a cliff and there's no looking back, but that's what life is all about.

So that's my thought process.

I appreciate that.

I'm sure you've hired the right guy.

But I know a lot of us will be -- you'll be sorely missed.

A couple questions.

On -- at North Dakota it looks like a lot of companies have entered the Bakken Play recently on the North Dakota side.

You guys have been pretty cautious there other than the [Mondak] area.

Are you feeling any differently about that play now on the North Dakota side?

Quite frankly, we're really not.

In fact, I'd almost say it's gone the other way.

We've looked at what other people have done and there's been a few different areas that people have been trying to play the Bakken there.

And frankly we haven't really seen what we consider anything we want to get into right at the moment.

So we feel like that side has probably gotten worse if anything with the passage of time.

Okay.

And then with the Centrohoma, it looks like you're having a lot of success in the Cromwell and Wapanuka;

Woodford so far isn't stacking up with what Devon and Newfield are doing.

Are they doing anything different or is that a matter of just where you are in the play?

We're very, very early stage and we've only drilled really one well that's had longer-term results and actually those results are economic on the one well that we drill, but not as good as what Devon Newfield saw.

And then our second well -- unfortunately we had a three stage frac, two of the fracs sanded out and so we think we're only getting initial production from the third stage.

What we did different on the third stage is we had increased the number of perforations.

And so you're kind of learning as you go.

So on the next one clearly we would complete it as we did the third stage of our last well, but we are in a learning stage.

We remain very optimistic.

On any of these resource plays at the early stages you're learning and ours isn't going to be exactly the same as the Newfield Devon, but we're learning from what they're doing and learning from what we're doing.

And I think at this stage of the game we continue to be pretty enthusiastic about it.

Given what they are seeing in terms of rates and reserves and given the success you're having in some of the uphole zones, any thoughts on your 3P potential now?

Is that I imagine increasing?

We haven't really changed anything from what we had at year-end.

We kind of -- in Centrohoma in total at year-end we booked 27 PUDs and 385 3P wells and kind of had total what we call 3P potential in the area of 240 Bcf.

And so that's kind of -- we haven't changed our view.

We look at our reserves at midyear; we don't really do a full reserve analysis every quarter.

Okay, thank you.

(OPERATOR INSTRUCTIONS).

Philip Dodge, Stanford Group.

Good morning, everybody.

Mark, all the best to you in your new endeavors.

Thank you.

And not surprisingly I have a question for you.

You were talking about the Wamsutter area and I noted two things that you've gone nonconsent on a couple of wells and, at the same time, drilling there is being delayed by rig availability.

The implication there is that others are a lot more aggressive there than you've decided to be for the moment.

We actually like the Wamsutter area.

You don't want to generalize an entire area.

There are areas in there that we've actually overall been very pleased with Wamsutter and have had good solid results for several years.

So it's an area we actually like.

It's somewhat of a statistical play but there are some areas that we like better than others.

And so when a well is proposed we look at the specifics of that well.

Nonconsent for geological reasons or just --?

Economics and obviously the geology is part of that.

Okay.

I have one other question but I'll stand back for a moment and then return.

(OPERATOR INSTRUCTIONS).

Philip Dodge.

Another company mentioned on their call that bad weather in April is reducing their June quarter production loss of electric power and that kind of thing.

Did that affect your Bakken Play?

I haven't heard that.

Okay.

I just wanted to check.

At this time there are no further questions.

Are there any closing remarks?

Just want to thank everyone for participating today and we look forward to our next quarter and having Tony aboard.

Bye-bye.

Thank you.

This concludes today's St. Mary Land & Exploration first-quarter 2006 earnings conference call.

You may now disconnect.