殼牌 (SHEL) 2008 Q1 法說會逐字稿

Good afternoon, ladies and gentlemen, and thank you for standing by. Welcome to the Duvernay Oil Corp. 2008 first quarter results conference call. At this time, all participants are in a listen-only mode. Following the presentation we will conduct a question-and-answer session. Instructions will be provided at this time. (OPERATOR INSTRUCTIONS). I would like to remind everyone that this conference call is being recorded today, Thursday, May 8, 2008, at 12:00 p.m. Eastern Time. I would now like to turn the conference over to Mr. Scott Kirker, Manager of Corporate Affairs. Please go ahead, sir.

Thank you, operator, and welcome, everyone, to our discussion of Duvernay's Q1 2008 results. Before we get started, I refer you to the advisory on forward-looking statements contained in the news release as well as the advisory contained in Duvernay's annual information form dated March 28, 2008, the latter of which is available on SEDAR. I'd like to draw your attention in particular to the material factors and assumptions in those advisories.

Mike Rose, our President and CEO, will start off with an overview of our operations and results. Following those comments, Mike and Brian Robinson, our Vice President of Finance and Chief Financial Officer, will be available for questions. Go ahead, Mike.

Morning, everybody, and thanks for dialing in. I'll start with the highlights and then move through the body of the release. We had record production and cash flow in the first quarter of 2008. We have increased our daily production level now to 27,500 boe's a day. We have expanded our EP program post break-up and we've done very well with the Montney play so far.

So moving to the results themselves, the production outlook first quarter '08 averaged 24,102 boe's per day which was 15% above the corresponding quarter in 2007 and sequentially it was 9% higher than the fourth quarter of 2007. So that's the second quarter in a row with very strong growth. Second quarter production so far has averaged 27,100 boe's per day which is 13% higher than first quarter, the one we're reviewing right now. The expanded EP program is expected to deliver net production addition between 100 mmcfpd and 115 mmcfpd from when we get going in late June through to April 2009 and these additions will come primarily from three projects, Groundbirch, West Groundbirch and the Sundance-Obed-Pedley area of the Alberta Deep Basin.

On the financial side, we set a cash flow record in the first quarter, $73.2 million or $1.22 per diluted share. On a per share basis, funds from operations were up 6% primarily due to production increases. On the earnings side, they were down due to the requirement to recognize potential unrealized natural gas hedging losses. Our actual before tax earnings from operations excluding these unrealized hedging losses were up modestly 3% to $23.5 million from $22.9 million in the first quarter of 2007. And as is typical of large resource development players, we engage in natural gas hedging just to ensure that we have a sufficient base level of cash flow to maintain the very large EP programs that we're conducting. We plan to continue to hedge between 25% and 50% of current production when natural gas prices meet or exceed levels utilized in our five year development plan. So we currently have 74 mmcfpd hedged for the balance of 2008 at a price of $8/mcf and that's representing 43% of production and that is the year one price in our five year development outlook. The unhedged budgeted volumes for the balance of 2008 of 97 mmcfpd obviously received the higher prices that are currently available. But I will point out that these hedged volumes at the $8 per mcf do yield an internal rate of return of 45% for our northeast B.C. and Deep Basin projects and our very low cost structure and above basin average deliverability gas wells allow these projects to remain profitable with prices as low as $3/mcf.

Improved natural gas prices and our continued EP performance have led us to increase our full year cash flow estimate to $400 million and our full year earnings estimates to $115 million. And also on the balance sheet side, the increased cash flow coupled with the equity issues we've done in 2008 and our small asset sale on the East Flank of the Peace River High will allow us to have year-end 2008 exit debt of $420 million which is actually 20% lower than where we exited 2007 at $526 million. So we have been focusing on continued strengthening of that balance sheet.

Also, we're in the process of finalizing our revised line of credit with our banking syndicate. It will go to $575 million from the current $515 million. Looking at the program itself, we are increasing our '08 capital program to $450 million to (sic) $400 million as previously announced and this allows us to expand our operated drilling rig fleet post break-up to 11 rigs from 9 rigs and that program will run continuously through until spring break-up of 2009. In conjunction with that expanded drilling program, we have facility expansions planned at Groundbirch, at Wroe, and Sundance-Obed in the Deep Basin to handle the increasing volumes.

Looking at the complexes themselves and starting in B.C., at Sunset Groundbirch we're expanding our rig fleet to five rigs and we will now have three rigs dedicated exclusively to drilling horizontal Triassic Montney gas development wells. So once we start up in mid-June we expect to add 35 new horizontal gas wells by spring break-up '09. Our first four Montney horizontals that we've actually drilled have all tested in excess of 5 mmcfpd and they were drilled for -- on budget at about $5.7 million per well, drill and complete. And one of those wells at Saturn tested at 9.5 mmcfpd. We have 180 net sections of Montney rights in what we interpret as the prime Montney gas resource fairway and, depending on what the ultimate well spacing is, either two or four wells per section, that will equate to between 350 and 700 horizontal drilling targets as we look into the future. To handle the increasing volume from those 35 horizontals we are expanding the Groundbirch 4-15 facility by 70 mmcfpd. That's an existing plant site already that's tied in directly to West Coast sales and that expansion will happen in two phases, 20 mmcfpd this fall, in September, and 50 mmcfpd next February, and that's phased to time to the production additions from the drilling of the wells delivered by those three rigs. We also have two other rigs in B.C. that will be operating targeting both Doig development wells and deeper Paleozoic exploration targets. That initial Paleozoic gas discovery that we announced with our year-end results is producing at a steady 4 mmcfpd at high pressure. It's choked down-hole as our facility infrastructure in that part of the world is currently full.

Also point out that as we drill more Montney horizontal development wells a number of the Doig development locations that we currently carry in inventory can be captured as up-hole zones in those upcoming Montney horizontals, so hence these 1.5 bcf to 2.0 bcf Doig zones can be added really for only completion and stimulation costs of about $600,000 per well and that saves you the drilling, casing lease construction costs of about $1.7 million. So it really improves the -- or it makes that Doig development inventory that much more valuable.

Looking at the Alberta Deep Basin, it currently isn't as glamorous as northeast B.C.,but it's by far our largest producing area and we have lots more to come. We have reached the 130 mmcfpd sales level in April and that's ahead of our original schedule and we plan to add a net 30 mmcfpd to that total by the end of 2008 via this expanded EP program. We've increased our Deep Basin rig fleet by one so we'll now have six operated rigs post break-up and the 30 mmcfpd planned increase will come primarily from the Sundance-Obed-Pedley area where we've drilled several very high deliverability wells during the past six months.

So far in '08 we're averaging nine completed and stimulated zones per well bore in the Deep Basin and hence the deliverability continues to climb from these wells. Both the Sundance and Oldman plants which started in November and March, November '07 and March '08, respectively, are full and we have several wells backed up and will keep those facilities full. Our development well inventory in the Deep Basin remains at approximately 1,400 locations. We have added 30 new sections of land in the Deep Basin so far in '08 through both crown sales and farming. So we continue to build that inventory. At Edson, where we announced our new pool wildcat Wabanum gas discovery with our year-end results, we plan at least two more wildcats in 2008, are in the process of pursuing licenses for those wells. And that is a play that does provide some long-term reserve and production upside for the Company.

That's all I was going say for now. We do have a new corporate overview package on the website that includes some new slides, so I refer you to that to get more detail on some of the points that have been made already. So we're more than willing to take questions.

Thank you. Ladies and gentlemen, we will now conduct the question and answer session. (OPERATOR INSTRUCTIONS) Your first question comes from Stephen Calderwood with Raymond James. Please go ahead.

Yes. Good morning. On the production growth that you outlined you quoted a net production addition of between 100 and 115 million cubic feet per day. Could you just clarify what you mean by net there. Do you mean net of declines?

Yes. It would be take the 27, 5 that we're currently at and we're going to try and add a net 100 million a day and there is a slide, Steve, in the new presentation package on the website that shows you where those additions are and how the split is between B.C. and Alberta. So it's 70 million a day in B.C., in two phases and it's 30 million a day in Alberta.

Excellent. Thanks. If I can ask another question on the Montney well, I'm curious as to why this one well would seem to produce at such an extraordinarily high rate of 9.5 million. Is that because there were more fracs in the wells, Mike?

I don't think we have enough wells into the whole play to understand sort of all the regional subsurface variability. I mean we're happy that all four are above 5 million a day and I think you're going to see variation between 5 and 10 and it would be a function of the lithology you penetrated, the effectiveness of your stimulations, the number of stimulations in the horizontal well bore. So we'll continue to learn as we drill and complete more of these wells.

How many fracs per well do you have?

We've averaged between five and the most we've done so far is eight.

Thanks.

Your next question comes from Richard Wyman with Canaccord Adams. Please go ahead.

Good morning, everyone, just to follow up some of Stephen;s questions there. In the 9 to 5 well was that one that got more than 5 fracs along the horizontal section or is it at the 5 fracs per well?

It had 6.

Okay. And in terms of the drilling are you getting enough scar tissue that you're starting to feel some efficiency in the capital program or are all these wells hanging in around 5 million all in?

Well, we'll see, when we do 35 between July and April I think that's where you see the efficiencies as we get going and start drilling multiple wells off the same pad and so forth. That's when you'll start to see some capital saving. The initial 4 wells are fairly widely spaced, as we seek to ascertain where the highest deliverability areas are or just see what the regional variability is.

Okay. All right. And then you mentioned that the up-hole Doig is going to come at you cheaper because of the penetrations into the Montney. Does that suggest that once the sting of initial production comes out of the Montney that you'd co-mingle the Doig with that or do you complete the Montney entirely before you go after the Doig?

No. We can co-mingle them and we have one well doing that already.

Okay. And then turning to the Deep Basin for a second here, when you're completing up to 9 zones per well bore, what kind of impact does that have on reserves per well compared to the previous experience where the completions were in fewer zones?

Well, we're seeing a steady increase. I think if you go back to '04, '05, we were averaging sort of 1.5 to 1.75 bcf per well and I think that recognition from our independent engineers is now in the 2.5 bcf per well range and we expect ultimately to be in the -- for the high deliverability wells in the 3 to 3 plus bcf per well bore range.

And is that change partly just well bore performance over time or is it directly attributed to more zones completed per well?

It's a combination. The early and life wells you didn't get a big reserve recognition because you were too early on the decline curve so, now those wells will flatten out, they see an increase but by adding more zones you're also improving the likelihood that you'll see a reserve increase.

Okay. And one last question. In terms of productivity that's locked up behind pipe awaiting facility expansion or just be able to maintain production at current levels until that expansion occurs, what volume would you estimate to be in that state?

Oh, in B.C., it's between 10 and 15 million a day and in Alberta it probably between 5 and 10.

Okay. Great. That's all for me. Thanks.

Thank you.

(OPERATOR INSTRUCTIONS). Mr. Kirker, there are no further questions at this time. Please continue.

Thank you. As there are no further questions, we will end the call here and thank all of you for participating.

Ladies and gentlemen, this concludes the conference call for today. Thank you for participating. Please disconnect your lines.