Veren Inc (CPG) 2012 Q2 法說會逐字稿

Good morning, ladies and gentlemen, my name is Melissa, and I will be your conference operator today. At this time I would like to welcome everyone to Crescent Point Energy's second-quarter 2012 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 for members of the investment community.

(Operator Instructions)

Thank you. This conference call is being recorded today and will also be webcast on Crescent Point's website. All amounts discussed today are in Canadian dollars unless otherwise stated. The complete financial statements and Management's discussion and analysis for the period ending June 30, 2012 were announced this morning and are available on Crescent Point's website at www.crescentPointEnergy.com and on the SEDAR website.

During the call, the management may make projections or other forward-looking statements regarding future events or future financial performance. Actual performance, events or results may differ materially. Additional information or factors that could affect Crescent Point's operations or financial results are included in Crescent Point's most recent annual information form, which may be accessed through Crescent Point's website, the SEDAR website, or by contacting Crescent Point Energy. I would now like to turn the call over to Mr. Scott Saxberg, President and CEO. Please go ahead, Mr. Saxberg.

Thank you, operator. I'd like to welcome everybody to our second-quarter conference call for 2012. With me is Greg Tisdale, our Chief Financial Officer, Trent Stangl, Vice President of Marketing and Investor Relations. Greg will speak to our financial highlights for the quarter.

We're very proud to announce our Q2 results and upwardly revised guidance. Crescent Point, again, has delivered another strong quarter. We significantly outperformed in the first half of the year relative to expectations, and we're upwardly revising our annual production guidance by more than 7%. Spring break up was better than expected, but most importantly, I think this increase highlights our strong drilling results in 2011 and the first half of 2012. Our water plug program in the Bakken and Shaunavon, as well as facility optimizations, have mainly contributed to this increase in guidance.

During the quarter we completed a Shaunavon consolidation acquisition and several on strategy acquisitions within our core areas that were highly accretive on all per share metrics. In addition, we were proactive in shipping oil via rail, completing an expansion to our rail facility in Stoughton, which allowed us to substantially increase our oil deliveries and to diversify markets through rail. We are well positioned as we move into the second half of the year to meet or exceed our targets.

During the second quarter, we added approximately 6,500 BOEs to our daily average over the first quarter of 2012. We grew our average daily production to a record of 96,900 BOEs per day, a 47% increase over our second quarter of 2011. This production growth really highlights the strength of our drilling inventory and shows our ability to execute growth on a per share basis. Overall, we spent CAD188 million on drilling and development activities in the second quarter, drilling 35 net oil wells with 100% success rate. We also spent nearly CAD48 million on land, seismic and facilities for a total expenditure of CAD236 million.

During the quarter, we completed several consolidation acquisitions, including the Shaunavon acquisition, which is a low-declined, long life, large oil in place asset. These assets include production of approximately 2,500 BOEs a day, which is 90% oil weighted, from three operated legacy units, and a non-operated unit that we believe has significant upside through ASP and in field drilling. The agreement is highly accretive to Crescent Point on all key metrics, and further solidifies our dominant position in southwest Saskatchewan. We are increasing our 2012 annual production guidance by more than 7% and we now expect to be more than 95,000 BOEs a day average for the year, which takes into account our transactions year-to-date, as well as the disposition of roughly 900 BOEs a day during the second quarter. We also increased our exit production by 2.5% to more than 100,000 BOEs a day. Again, this is a result of our strong drilling performance in 2011 and the first half of 2012, as well as our success in our water floods and facility optimizations.

We're keeping our capital program basically the same, CAD1.25 billion, and we'll stay focused on executing our organic growth projects in our large resource in place assets, developing emerging plays and expanding our water flood programs. Because of our strong production results in Q2, we decided to delay drilling until the beginning of August, which will allow us to capitalize on reduced costs and to optimize our remaining budget. We believe that reduced industry activity will alleviate cost pressures in the second half of 2012, leading to improved operating costs and capital efficiencies across all areas. We will continue with our hedging strategy and balance sheet discipline, maintaining a low debt to cash flow, and look to continue to diversify our markets with rail, which is opening up new markets and allowing us to manage pipeline disruptions.

We are currently more than 16,000 barrels a day shipping through our Stoughton rail facility with an additional 1,000 being delivered through third party rail sites. We plan to expand our rail facility and ramp up to 40,000 barrels per day in Q4. And in addition, we're looking at developing rail capabilities in our other core areas. With record Q2 production, we're well positioned to meet or exceed our targets again for this year.

Before handing things over to Greg, I'd like to thank the Crescent Point team for its hard work in executing another fantastic quarter, and we're very excited about what we've achieved in the first half of 2012, and look forward to a strong second half.

Greg will now cover some of the financial highlights.

Thanks, Scott. I'm pleased to report that Crescent Point generated cash flow in the quarter of CAD386 million or CAD1.19 per share. This represents a 4% increase over Q2 2011 on a per share basis. This increase in cash flow is supported by our record production generated in Q2, and is even more impressive given a CAD15 reduction in realized commodity prices from the prior year.

On the finance side, we had an active quarter as we closed the private placement of long term notes and increased our syndicated bank line by CAD500 million. With respect to long term notes, we issued $268 million notes and CAD32 million notes, with terms ranging from 7 to 10 years and coupon rates ranging from 3.39% to 4.76%. With these notes, our total long-term notes outstanding at the end of the second quarter is CAD838 million.

In the quarter our bank line was also increased from CAD1.6 billion to CAD2.1 billion. At the end of the quarter, approximately CAD1.1 billion was drawn on this facility, providing us significant financial flexibility with approximately CAD1 billion unutilized. Our cash flow forecast for 2012 is CAD1.47 billion based on a WTI price of CAD94 a barrel. We continue to drive our payout ratio down and manage our price loads with our disciplined 3.5 year hedge book. We actively hedged commodity prices in the second quarter, capitalizing on high commodity prices throughout the forward curve. We are now 57% hedged for the balance of 2012, 51% hedged for '13, 32% hedged for 2014, and 14% hedged for 2015 on our oil production.

As Scott mentioned, shipping crude on rail also acts as a hedge to the volatile price differentials we've been seeing and expect will continue through the year. We plan on increasing crude deliveries through our Stoughton rail facility allowing us to sell to new markets and to protect against this current price volatility on pipeline differentials. Given the strength of our balance sheet and hedge portfolio, we are well positioned to continue to generate further strong operating and financial results for the balance of 2012 and beyond.

I'll now hand things back over to Scott.

Thanks, Greg. Again, we've had an outstanding first half of the year and we're looking forward to the rest of 2012. At this point we're ready to answer any questions from members of the investment community. Operator?

(Operator Instructions)

Brian Kristjansen, Canaccord Genuity.

Good morning, guys. Scott, I had a question trying to break out the guidance increase between how much was due to the mild breakup and how much was due to the water flood impact. Can you put some numbers around those?

I think it -- you know, we had success, I think, in all areas. When you kind of -- I think when we came through Q1 in looking at what our results were from 2011 and then rolling into Q1, that sort of carried on through our process, so probably 3,000 barrels a day, 2,500 barrels a day of that is just baseline production that exceeded our expectations from budgeting the year before. So, I'd say about half of -- half of that is just based on water flood, facilities optimizations that we did in Shaunavon and in the Bakken that carried throughout the year, so about half of it is based on that.

Okay.

And then breakup, obviously, wasn't as bad, so our average for the year, you know, the other portion of that average comes, I think, from the fact that we didn't have as much down time in Q2.

Okay. Sort of 50/50, then. Okay. Thanks.

Gordon Tait, BMO capitol.

Good morning. Just on -- you mentioned you were going to delay some of your capital spending into the middle of Q3 and it would result in some kind of cost savings. Are you able to kind of quantify, is it like a 5% or 10% savings, or what are you seeing out of the service companies you're negotiating with?

Yes, that's a great question. We -- you know, back in May when prices started to come off in May and June, and then we were well ahead of our production numbers, we made a call to first delay our drilling to July 1 and go back to the service providers and say, hey, give us some cost reductions. Although oil is, you know, CAD90 or CAD85, price differentials have come off and that environment has changed, and so we need to see some reduction in costs.

And then we -- so we got some feedback on that, and then as we got further through Q2 to the end and we were well ahead of our numbers, we decided to, again, push off our drilling to beginning of August to mid-August, and went back again those service providers to ask for some -- for discounts, because at that point we were contemplating changing our budget, And we had some really good positive feedback from service providers in that we're seeing anywhere from 10% to 15% sort of cost reductions. We're kind of banking on really probably more like 5% to 10% and so, you know, until you see it kind of happen, so I'd say it's sort of about 5% to 10%.

And then in terms of number of wells drilled, I think you had about 157 net wells first half of the year. How many are you looking to getting completed by year end?

So with our budget allocation -- so part of the -- also, what was positive for us was to allow us to adjust our capital program and where we're spending money in the different areas. And so we decided to go through that process, and so we're actually drilling less wells than probably original budget, mainly because some of the capital we've shifted to Swan Hills and then into North Dakota. And we're seeing good results in both of those areas. And so our well count, I think we've dropped by probably 50 to 60 wells.

Those are more expensive wells, correct?

Yes. So, we're probably going to -- we're going to drill in total something like 330 to 350 kind of well count, depending on that final allocation. So, about 180 wells left to drill by end of the year, I think.

Are those net wells?

Net wells, yes.

Okay. And then just one question on the -- your Stoughton rail loading. Just based on where the current prices are, differentials, what's the cost/benefit relationship there? There's an increase in the cost using rail typically, but what is the pay off in terms of your realized prices?

Well, partly with our rail facility out in Stoughton, especially we were very lucky in that that rail line goes right through our field and right beside our battery, so the capital costs to expand from 16,000 barrels to 40,000 is fairly minimal relative to that. We've made -- we've had to pay out -- we've already paid off our rail facility, basically.

And then when it comes down to pricing, we're able to ship rail to several different markets and diversify our markets, so we're early days, I think still in shipping rail. And so, we really think that the marginal difference between pipeline and rail, it's CAD1 or CAD2, a couple of bucks difference, and we could potentially long term with that diversification, you could make an argument that it's really not that significant differential between the rail. So -- and pipe. So, Trent, maybe you can step in.

Yes. I think when you look at long term, you're looking at one or two bucks. So far this year with the volatile differentials we've seen on the pipe, we've probably seen about a third of the volatility on the rail side on our differentials than we've seen on the pipe. And to date this year, rail at best has been -- at worst has been equivalent to pipe, and at best has been significantly better than (inaudible) on the pipe side. Really the key there is the volatility is a lot lower, and we've been able to lock in some differentials through the rail, as well, for 6- and 12-month terms.

I guess there's no risk of being apportioned then?

No, no.

And then one of the things that you also have to factor in is, you know, costs. Like we saw over the last two years because of Enbridge's disruptions and pipeline failures, costs on the pipe going up and additional fees, and so you don't know where that's going to be headed long term with those kind of continued disruptions.

So we're early days, I think, on the rail side, but we're seeing some pretty positive pricing and it gives us a lot of flexibility. At the end of the day, the main reason we put the rail facility in in the first place was to give us that flexibility around, and reduce our risk around pipeline disruptions.

Okay. Thanks.

Jason Frew, Credit Suisse.

Hey there. Scott, I wonder if you could walk us through the steps toward a unit wide water flood in the Bakken, and maybe give us a road map as to how that progresses in time, and when you might see it in more of a step change in your decline rate and your reserve booking?

Well, we're full on unitizing the main core of the Bakken play. We're continuing to expand the water flood and add more injectors. At the stage we're at right now, we have numerous years of water injection conversions before we really need to unitize lands, per se, to be impactful. So, the first step is to convert wells on our crown lands in through the units and then unitize. We're thinking unitization should happen next year based on the pace that we're going, so well within time frames of converting producers to injectors on our crown lands.

On the reserve booking side, we've seen positive reserve bookings on the older sort of patterns or near injector wells, more focused on performance, but then at the same time we're converting producing wells to injectors, so we lose reserves on those injectors, and then they get added to the offset producers. So you kind of wind up with a net net zero in the short-term. But we're seeing pretty strong performance across the board, not only at the Bakken, but also Shaunavon, and so as you get more data and months go by, we'll add reserves on those wells, and it just sort of gets built into your long-term -- long-term reserve adds with minimal capital. So it's one of those, it's a long-term, year-over-year add.

We don't expect to go from like a 12% recovery to 20% or something overnight. It's more of a 12% goes to 13% to 14% to 15% year-over-year for a long time. And that's just the nature of how conservative engineers book reserves at year end and third party. We know technically, we believe recovery factors are going to be in the 30s, mid-30s and I'm more convinced as we've drilled more wells, we've drilled now well over 2,000 multi-stage horizontal wells in Canada and through these fields.

And then with more water flood data, we're seeing that unconventional type reservoir act more like a conventional reservoir. And so you may see recovery factors move more towards a conventional recovery factor versus the initial theory of low recovery and tight reservoirs. So, we're pretty excited about that.

Okay. Thanks for that color.

Yes. Thanks.

(Operator Instructions)

Cristina Lopez, Macquarie

Hi, guys, just a couple of quick questions. The first one is with respect to potential cash taxability. What are you looking at for a time horizon now given continued strength in both your production volumes and with the commodity?

Yes, it's Greg here, so we have CAD7.5 billion in taxables, and our tax horizon, given current commodity prices, is slightly taxable in 2014, and really 2015 is when we'll be taxable.

And at that level it's sort of 7% or something like that going to -- in our five-year plan, it might be.

10%.

It goes to 10%.

Okay. The other question I have is obviously you -- the acquisitions were financed with the balance sheet, balance sheet still looks very strong. Is the idea to keep this just as a financing using your balance sheet, or is there thoughts of issuing equity around this to further shore up balance sheets?

Well, you know, obviously we're in a very strong position. We've had a very successful first half of the year. We see lots of opportunities ahead of us, not only on the [AF] M&A front, but just on our drilling and drilling inventory, and so, we're going look to raise equity when required, when there's a need and keep financially strong.

And then the last question I have is with respect to your decline rate. Given the strength you've had with your water floods, where are you seeing the decline rate today, and what are you projecting now as part of your five-year plan for kind of 2013, 2014 for the decline rate?

Yes, that's a good question. So we've -- it's sort of a -- it's probably three different parts to it. We've -- we did about 20,000 barrels a day of acquisitions this year, of which a good chunk of those are low decline transactions. And in addition, we've seen some pretty good response on our water floods and just baseline decline -- just even on our -- we've gone from our 16 stage packers plus to 25 stage cemented liner, and our 25 stage cemented liners are outperforming any of our previous completions, and have lower initial declines that we're seeing.

And so a lot of our up performance has been due to that single change in our completion technique. On a corporate basis, we used to, in our budget plan, be kind of around 34% annualized decline, which is conservative. It's probably more like 31%, 32% and so obviously we're budgeting a little bit more conservative. But currently we're now seeing that more like 32%, and so I would probably argue on a reality basis we're probably sub 30% right now, based on how things are looking, but we kind of budget around 32%.

Perfect. That's it for me. Thanks, guys.

Great. Thanks.

Brian Kristjansen, Canaccord Genuity.

Thanks. Just had a couple of more questions with respect to the reallocation of capital to Swan Hills in North Dakota. Is that predominantly -- are you seeing, I imagine costs are still sticky in Swan Hills, or has the reduced programs from your smaller competitors freed stuff up there? And what's the status on North Dakota? Is that productivity or cost reductions there or both?

That's a great question again. It's interesting because -- so in the first half of the year some of our partners and competitors went really hard with drilling rigs and completions, and it really got a bit crazy up there. And when we finished Q1, we kind of said, hey, we've got to pull this back. We saw the capital cost escalation, just asset price costs had gone up extremely high and we -- you know, we have long tenured land, like it's nine-year tenure land, so we don't have to drill it that quickly.

And so we've -- we went back to our partners, we did some -- quite a bit of work with our service providers, and so we pulled back dramatically on drill counts and drill rigs there. And so we pulled back, I think, to two rigs to the end of the year. And so we're now -- yes, we saw higher capital costs per well there in first half of the year and now with our new completions that we've done just more recently in July here, we saw the costs come dramatically down, back to our -- what our original type wells were. So, we were seeing costs well over CAD6 million, almost CAD7 million on some of those Swan Hills wells.

Okay.

And we're now back down to the CAD5.5 million, CAD5.3 million kind of per well costs and so, you know, obviously -- hopefully that sustains through to the end of the year and that's our expectation. And then in North Dakota, despite the drop in prices, guys down will are still very active drilling. We are starting to see some softening in North Dakota with more availability of drilling rigs and frac crews. What we did there was we changed our completion technique and went to more ceramics. And so our costs are higher on a per well basis, but then our productivity has been better.

So that's sort of the interesting thing about both areas, Swan Hills and North Dakota, the production and reserve results have been very encouraging, and very strong. And so really for us, we feel it's just a matter of driving costs down in those areas, and that's basically what we've been focused on for the second half of the year.

Great. Thanks, Scott.

Thanks.

Jonathan Fleming, Cormark.

Hi, Scott, just touching on that North Dakota operation a little bit more. I wonder if you could comment or give a little color on the M&A market opportunity down there? We know last year there was a lot of activity, and is that kind of activity level still driving high prices to enter the play on?

Yes. We -- I mean, we had a three-part approach to North Dakota, and then we saw the opportunity and that there are high costs to drill. There's a CAD10 price differential, you know, built in, that's probably more like CAD15 now or it has been. And then we just saw from our knowledge base from Viewfield where we drilled up our Viewfield pool and we saw, and you've seen it, the change in completion technique and then, therefore, reserve adds and reserve growth.

So like in Viewfield, we started out with a 75,000-barrel type well. Now in that same part of the field, we're upwards of 200,000, 225,000 with more knowledge and time. And so, we see that same sort of view in North Dakota. Those are all in our viewpoint a cheap entry point into North Dakota because of those three factors. When you're doing acquisitions, all those kind of factors are built in that we feel suppress the values in those areas.

At the same time, though, so what we've seen, I think we'll go out six months, is a lot of activity levels, but a good portion of deals that have gone no bid or not -- or where guys aren't willing to sell at the levels based on current commodity prices. So, there's been a lot of activity, but not as many transactions that there could have been, I think. And so we've been involved in looking, obviously, at a lot of transactions through North Dakota. We're also -- have been active and proactively looking at other basins within the US. Now with our Denver team and the bench strength that we have down there, we're able to evaluate more than just the North Dakota.

And with our multiple expertise in the Bakken, Shaunavon water floods, completion techniques with Swan Hills, with the Viking and North Dakota, we bring to the table a pretty vast expertise that's unique, I think, to going into the US, and the fact that we've drilled over 2,000 wells and completed wells in probably 100 different ways. So, we are actively looking at other areas and trying to see whether we can be at the forefront of some of the newer plays.

Then, Scott, if you were to look three years down the road into your crystal ball, would you see yourself in two or more basins in the US then, or how do you see that growth building itself out over the next couple of years?

I think we're probably -- we're -- you know, we obviously want to stay very focused and I think we've been that way in Canada, and so, I would say we're probably in one or two play types. Obviously, we're there in North Dakota, so to add another one probably isn't that difficult. When you get beyond that at this stage, and we're talking probably long term, 5 to 10 years, maybe we're in a similar number of basins as we are in Canada, but we obviously -- we've done very well staying very focused.

All of our deals we've done this last eight years have all been tied into our existing infrastructure and facilities and areas that we've got our expertise in. So, we're taking our time and building our way into plays.

Good stuff. Thanks very much.

Great. Thanks.

There are no further questions at this time. I'll turn the call back over to the presenters.

Great. Thank you much. Thank you very much, everybody, and we look forward to another great half of 2012.

Thank you, ladies and gentlemen, for participating in Crescent Point's second quarter 2012 conference call. If you have more questions, you can call Crescent Point's Investor Relations department at 1-877-403-1678. Thank you and have a good day.