Veren Inc (VRN) 2013 Q1 法說會逐字稿

Good morning, ladies and gentlemen. My name is Teresa and I will be your conference operator today. At this time I would like to welcome everyone to Crescent Point Energy's first-quarter 2013 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)

This conference call is being recorded today and will also be on webcast on Crescent Point's website, but may not be recorded or rebroadcast without the express consent of Crescent Point Energy. All amounts discussed today are in Canadian dollars unless otherwise stated.

The complete financial statements and management's discussion analysis for the period ending March 31, 2013 were announced this morning and are available on Crescent Point's website at www.CrescentPointenergy.com and on the SEDAR website. During the call, management may make any 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. Management also calls your attention to the forward-looking information and non-GAAP measures section of the press release issued earlier today.

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 everyone to our first-quarter conference call for 2013. With me is Greg Tisdale, our Chief Financial Officer; Neil Smith, our Chief Operating Officer; and Trent Stangl, our Vice President of Marketing and Investor Relations. I'll give an overview of some of our highlights from the quarter and operations and then Greg will speak to our financial highlights.

We are happy to report Crescent Point executed a strong first quarter and delivered record production of more than 117,000 BOE's per day, exceeding our initial annual production target by more than 5000 barrels a day. Our outperformance during the quarter was driven by several factors, including the success of our waterfloods, the outperformance of cemented liner wells and the application of new technologies and techniques across our asset base. This really highlights the strength of our management team, our technical teams and field staff, as well as the magnitude of our asset base, the depth of our drilling inventory and the tremendous upside we have within the Company. We also accomplished more drilling and completions in the first quarter than we planned, thanks to a delayed spring breakup that continues to look less severe than we expected.

As a result of our outperformance during the quarter, we upwardly revised our production guidance and capital expenditures for the year. We now expect our average daily production for 2013 to be 114,000 barrels per day and our exit rate to be 117,000 BOE's per day. We expect to spend CAD1.5 billion in total, an increase of CAD150 million.

Looking closer at Q1, we grew production by 30% over first quarter 2012 and by 9% over fourth quarter. We grew cash flow by 14% over first quarter 2012 and continue to increase our oil shipments by rail, which is allowing us to reduce our exposure to price differentials and volatility. Subsequent to the quarter, we started shipping oil by rail through a third-party facility in Utah and we expect to have our own rail loading facility there up and running in late Q2. We also are pleased to report that subsequent to the quarter received approval from the Saskatchewan government for our first Lower Shaunavon unit. The approval is a major milestone for us because it allows us to implement the Lower Shaunavon waterflood across a large area. This government approval reinforces the success of our waterfloods to date and affirms the success in horizontal multi-stage fracking combined with water flooding. We will continue to pursue approval for implementation of a second Lower Shaunavon unit and four proposed units within the Bakken.

Looking at the rest of 2013, we plan to spend the majority of capital increase on drilling and completion activities and depending on commodity prices, we may increase our capital spending plans again later in the year. We will continue to focus on developing our high-quality asset base, including the implementation of our waterfloods, and to refine new techniques and technologies. We are on our way to having a great year of organic growth and looking forward to meeting or exceeding our targets again this year.

On the operational side, we had a very active first quarter, driven in part by the delay spring breakup that allowed us to drill and complete more wells than we planned. Overall, we spent a record CAD459 million on drilling and development activities, drilling 164 net oil wells with 100% success rate. We also spent nearly CAD74 million on land, seismic and facilities for a total capital expenditures of CAD533 million. During the quarter we continued to develop and grow our core Bakken and Shaunavon assets through development drilling, our waterflood programs and the application of new technologies. These factors and others have contributed to our performance during the quarter, such as in southeast Saskatchewan where several of our horizontal wells in the convention zones far surpassed our initial production expectations.

We're very excited about our Lower Shaunavon waterflood unit and continuing the approval process on our second Shaunavon unit and then our several waterflood units within the Bakken. I can't emphasize how significant that is on a general basis for reserve upside, [dampening] of our production declines and growth for the Company into the future. We continue to develop our emerging plays including the Beaverhill Lake in Alberta and Three Forks in North Dakota Bakken. And we drilled 27 net wells in our Uinta Basin in Utah.

We're pleased with the results in Utah, having now seen wells come on above or at our expectations. Currently production in the play is greater than 9000 barrels a day, which is a 15% increase from production when we acquired Ute Energy. Later this year we plan to implement a 3D seismic program that will cover a large portion of our lands that we operate in the Randlett area. We have successfully integrated and are fully staffed in our Denver office and are well underway to having a successful year in the US.

On the rail front we continue to increase the amount of crude we shipped through our facilities in Saskatchewan and Alberta, which has given us access to new markets and reduced our exposure to crude oil price differentials. First quarter average rail throughput for our three facilities combined was approximately 31,500 barrels per day. We also recently began shipping oil in Utah through a third-party facility and we look forward to getting our rail loading facility in the area operational later in second quarter. We're pleased with our first quarter results and feel we're in a great position so far in our second quarter.

Before I hand things over to Greg, I would like to thank our field staff and HSC staff, who are the best in the business. Thanks to all for your hard work so far this year.

Greg now will discuss our financial highlights. Greg?

Great. Thanks, Scott. I am pleased to report that Crescent Point generated cash flow in the quarter of CAD456 million or CAD1.20 per share. This represents a 14% increase over the CAD400 million generated in the first quarter of 2012. As a result of our strong first-quarter results, we have upwardly revised our annual production guidance by 2000 barrels a day to an annual average of 114,000 BOE per day.

Our 2013 cash flow guidance was also upwardly revised to CAD1.8 billion based on a WTI average $92 a barrel. On the hedging front we continue to hedge commodity prices in the first quarter. On our oil production we are now 55%, 39%, 21% and 4% hedged for the balance of 2013, 2014, 2015 and the first three quarters of 2016 respectively. Crude oil differentials remain volatile with wide differentials in the first quarter of 2013.

Looking into the second quarter, we have seen oil differentials improve relative to Q1. With our crude oil rail operations, we have effectively managed this price volatility and we sold approximately 31,500 barrels a day on rail in the quarter. In addition, we have locked in 18,000 barrels a day of production for the balance of 2013 at average selling prices greater than $90 a barrel.

We remain disciplined in our approach to capital spending. Including our upwardly revised capital expenditure budget, our balance sheet remains strong, with projected net debt to cash flow of approximately 1 times and significant unutilized credit capacity. Given the strength of our balance sheet, hedge portfolio and operational momentum, we are well-positioned to continue to generate strong operating and match results for the balance of this year and beyond.

I will now hand things back over to Scott.

Thanks, Greg. Again, we have had a great first quarter. We had record production and continue to outperform operationally in our Bakken and Shaunavon fields. We are pretty excited about the early shipments of crude rail or crude out of our Utah area and the establishment of a strong, building strong markets there and reducing differentials. We're also really excited about the recent approval of our first unitization at Shaunavon and I can't speak more clear to that of how exciting that is for us. And just the sheer size of that unit. It is one of the largest units created in Saskatchewan history.

So, we've got a lot of momentum so far this year and we are looking forward to another solid year and I'd love to answer any questions. I will hand it back to the operator. Thanks

(Operator Instructions)

Brian Kristjansen of Dundee Capital Markets.

Given the better-than-expected breakup, can you provide some color on how you see CapEx being allocated in Q2 in the second half? And then where the incremental CAD150 million is getting directed?

Okay, good question. With the delayed breakup, what it did was give us higher flush production heading into the quarter. In Q2 we don't have plans for extra spending or drilling activity in Q2, so in our budget we basically don't really get started drilling till middle to end of June. And that is sort of consistent with what we had in the past. But the fact that we had more flush production heading from March into April. Our April numbers are very strong, and so we are well-positioned.

And so that CAD150 million capital -- some of it was spent in Q1 because of the delay of breakup -- probably about CAD50 million, CAD75 million or something like that. And then Q3 and Q4, that capital will be spent across that. Some of that is just with our gas plant expansion in Viewfield, and some facilities adds later in the year.

Thanks. And then, can you comment on the timing of the [Leachville] approval relative to when you submitted it, and can we expect to see similar timing on the Bakken units?

On the timeline -- we have been working on these units for probably a couple years now. Of course, with the consolidation activity that we had over the last couple years, it's made it easier for us to push those applications through. So, our expectations for the Bakken applications are sort of the end of the year, beginning of next year timeline. This is the first unit that's been created in like 20 years of this size and magnitude. And so, obviously it takes a lot of work when you're in that size of a field. I think this field is like the third largest unit created or something like that.

The next unit is going to be in that equivalent size in the Lower Shaunavon. And then the Bakken units, little more complex with the fee title ownership and crown mix, and we're proposing four units there. So, we are hoping the first unit will get approved, as I said, again, late this year, early into next year.

Thank you. And one last one. Can you quantify the impact on your differentials from what you have railed to date in Utah, and where you could expect that to go once your loading facility's operational?

I'll have Trent answer that.

Sure. It's been most dramatic in Southeast Saskatchewan, where you have got the highest throughput overall. We have a combination of spot and term deals, and between those -- that mix, we are probably about $5 and $6 a barrel better on the rail. That moves from month to month depending on what the pipeline prices are doing. For example, in May here, pipeline prices are really quite strong, so you would not see that same spread on the rail.

And in Utah, we are basically -- these are our first deals, so we're just at the stage right now -- we are just building the markets for that crude, and so we don't see at this stage a big gain on the rail side versus shipping into Salt Lake. But it's the early -- obviously, our first deals and stages of outflow.

There is really a lot of benefits to the rail. For example, in Southwest Saskatchewan right now we have been expanding the capacity of our rail facility at Dollard, and the timing has been quite good because we have had some pipeline issues due to some flooding in Moose Jaw, and so we've been able to divert that pipeline crude by rail and by truck to keep our production going during the pipeline issues.

Perfect. Thanks, Scott. Thanks, Trent.

Yes, thanks.

Kyle Preston of National Bank.

Just regarding this potential budget increase at the end of the year, can you guys give an order of magnitude on how much you might increase it, and what signs you will be looking for to make that decision?

Similar to -- in past looking at where commodity prices wind up towards the end of the year. I think we want to get through the summer -- July and August, and see where our production is headed, and typically we look at adding capital sort of in November, December in our budgeting. And so, probably similar magnitude of the CAD100 million to CAD200 million range, and again, subject to where commodity prices are. We have got a lot of projects, obviously, with our large inventory, over 6,000 or 7,000 drilling locations ahead of us. So, we have a lot of possibility to add capital and grow a little bit faster. So, we are watching that, and we want to kind of get through the Summer months and then make a call to add onto the back end of the year to set us up for strong growth for 2014.

Okay, thanks for that. And just a follow-up question -- or not a follow-up -- a new question on -- you had mentioned or you talked about potential reserve upside from your waterflood. Is that something you'd expect this year, or are you just thinking future down the road?

Yes, I think, obviously as we add more injectors and fill out the units, we will see reserve adds there. The reserve adds in these units are over a long-term period, so we wouldn't expect a big, huge lift to be across the board in these units. But what happens is now guys are looking at these -- instead of individual well reserves, we will be looking at large block reserves on the unitization and units, so the engineers look at it as more as a larger entity versus individually. And it will be based on the performance of the total unit versus well by well. So, we expect over the long term and as we add injectors and implement the waterflood there that we will see those reserves. But it is usually a gradual add year over year with low F&D.

And Kyle, it is Neil Smith here. One of the examples you can use is the Tatagua unit that we acquired when we first turned into an energy trust. Typically what you'll see is with the independents, they will want to see some performance. So, that unit -- it was about a 6.8% recovery factor on the waterflood when it was initially unitized and flooded. Fast forward over five or six years, that was close to 12% that the independents were giving to it. So, what you should anticipate is the first year on the Shaunavon unit it (inaudible - technical difficulties) by the independents, and as we develop it and prove it up, just in the same way that we have strong, positive incremental reserve additions every year, we've had year over year. We are anticipating we will see that development. So, it will be a lower number to start, and with time the independents we anticipate will increase that.

And I would also point out -- so we will have our new presentation should be online here on our website, and within that presentation we've created two new slides, one showing the Shaunavon -- Lower Shaunavon unit and oil in place, the current recovery factor, and then our potential recovery factor due to waterflooding. And also, on all the proposed units in a table there. So, I would refer you to that table to look at, to see what the potential impact is. It's close to something like 380 million barrels of incremental reserve adds just from these units that we are proposing over time.

Perfect. Thanks a lot for that, guys.

Travis Wood from TD Securities.

Most of my questions have already been asked, but I will ask a question around rail. I just want to make sure I'm reading this right. Of the rail volumes that are moving today, or have moved through Q1, is the term contracts the 18,000?

Correct. The term contracts are the 18,000 out of the 31,500 -- so not quite two-thirds.

Okay. And what type of term is that on -- when will that expire?

The 18,000 runs to the end of the year, and then we have another 14,000 for the first half of next year.

Okay. And then with the rail expansion in Utah, what capacity is that going to be built for?

We will be starting up with 5,000 barrels a day, but it's fairly easy to add the capacity, as you have seen with our Southeast Saskatchewan one, where it is really a matter of adding in transloaders and so on. We have got enough space expected to be able to get up to unit train size in our plans for Utah. But that would be something we get built up over time.

Okay, perfect. Thank you.

(Operator Instructions)

Gordon Tait of BMO Capital Markets.

Just to go back to the waterflood, we did provide some quantification around the impact of the incremental reserve recoveries, but how big an area is it aerially? How many sections or wells would be affected by this waterflood?

In the Lower Shaunavon, it's roughly about two townships big, I think, in size. So, fairly significant aerial-extent-wise. And remember, the Lower Shaunavon is about three or four times thicker than the Bakken. So, on an equivalent basis, that unit is -- on an oil and place basis, it is about 880 million barrels, so pretty significant size.

And then -- well, now that you have had some success with unitization in Saskatchewan, do you think it is then less likely you would need to consolidate interest now that you seem to have a unitization process well in hand?

That's a great question, Gordon. We own 100% of the Lower Shaunavon units, and 100% of the Bakken units. So, yes, we would not have to consolidate those anymore. (laughter)

Okay, that would do it. And then at one point you were not spending as much money at Swan Hills in North Dakota because of cost. I think there were some pretty big cost pressures there, but it looks like you are going back in those areas. I don't know if I'm reading that right, but are you seeing some abatement in capital cost in those areas?

Yes. In Swan Hills, for sure, we've seen the cost drop, and in North Dakota, but at this stage we have not expanded our CapEx in those areas yet. In Swan Hills, really there we are in the early stages on the production side, and so we're waiting to see the results there, and we are also testing a couple different completion techniques. And so those are areas that later in the year we may add production -- or capital to. In North Dakota, we switched over from the frac techniques that are more standard down in North Dakota to our frac technique that we have developed in Viewfield. And so we are early stages on, I think, about four wells there that we have tested that in. So we want to see the production results there, and then we'll probably get back to drilling in North Dakota later in the year.

On the non-upside, we've seen a tremendous amount of activity in North Dakota. So, we are setting some dollar -- extra dollars aside for non-activity in North Dakota. But in general, in North Dakota, the costs have come down across the board there, and we will see that pressure continue as time goes on.

Okay. And then just with the railing out of the Uinta Basin, is it still going into the Salt Lake City refineries, or are there other refineries that can take that high-paraffin-content oil.

That crude where we are shipping it is -- we are shipping it all the way to the East Coast.

And so there's no issues with shipping oil with that kind of a waxy content, or with other refineries accepting it?

Gordon, it is Trent here. It's really the same as railing heavy crude, where you use the coil and insulated cars, and then you steam offloading at the end loading end. We have had a lot of interest in the Uinta Basin crude from refiners across North America. In the long run, we are going to see those cars going to the West Coast, the East Coast, the Gulf Coast, and there's nothing really tricky about refining it. It has got some really nice yields to it.

All right. Thanks.

Brian Kristjansen of Dundee Capital Markets.

Thanks, Scott. On the -- you mentioned the conventional results far surpassing expectations. Can you give us some details, and is this due to sweet spots or some technology improvement?

Brian, it's Neil here again. It's more related to a lot of the Frobisher wells. We talked a little more about that two or three years ago, where, when you have a large land position that we built up in southeast Saskatchewan, particularly the Bakken. Every time you drill down through the Bakken, you get a free look at the Frobisher. The emphasis, obviously, has been our big, large resource play, but the Frobisher continues to exceed expectations in a number of different areas as well. So, we did about 15 net conventional -- so-called conventional wells during the quarter, and half of those were much better than what we expected they were on our type wells.

Yes, that contributed probably about 1,000 barrels a day.

Yes, close to 1,000.

Above our numbers.

Thanks.

[Shavead Marawat] of CIBC World Markets.

Sorry, I missed the beginning of the call, so I apologize if this question has already been asked. Just kind of wondering what -- give me the potential benefit for Uinta margins on your railing strategies, since you are there more in terms of in the future when your own operations come on in Q2 and Q3?

Sorry, that was what the rail margins in Uinta?

Exactly.

When you look at that crude going back sort of 5, 10 years ago before the basin growth, the production growth rate starting to kick in, you were looking at a WTI minus $2, WTI minus $4 price. And recently it's been more like a WTI minus $15, $16, $17. So, we think the upside there is a good $5 to $10 a barrel by tightening up that market and getting some of the crude into some alternative markets.

Okay, thank you.

Mike Harvey of RBC.

Good morning, guys, I think my question was just answered there. But can you just give us a sense for your activity levels in North Dakota? It looks like you drilled about 67 wells in the US, with only about 27 in the Uinta, so it looks like you could have gotten a little active in other parts of the US?

No, I think it is just a math, that's just a bit of a math --

Most of our drilling this year is in the Uinta Basin. So, it is 75 wells in the Uinta Basin versus, with our expanded budget we are going to do four in North Dakota. And that level of drilling is down quite a bit from last year, as we discussed. With having the higher cost in North Dakota and needing to see those capital costs come down, we've cut our capital way back in North Dakota, and we have diverted that into the Uinta Basin, where we have got wells that we're drilling for $1.6 million versus $10 million or something like that.

So, the 67 -- there's a large non-op component in North Dakota. So, like 14 or 15 wells gross are actually like 3 net. So, in the math that you are stating of, that is the gross number, 67, and our net number is 3.2. So, I think that is what you are --

Got you. Thanks, guys.

It's Neil here again. We are being extremely disciplined in the selection of our wells in North Dakota. There are a number where we have small working interests. We are receiving a number of notices from partners. We are electing not to participate in several of them, just exercising some capital discipline just more related to the capital costs are higher than what we think they should be on some of those minor lands that we're not participating. There is a definite capital discipline being exercised in North Dakota.

Great. Thanks, guys.

You have no further questions registered at this time. I will turn the meeting back to Mr. Saxberg.

Great. Well, thank you very much for participating in our conference call, and we are very excited about the remainder of 2013 as we go forward. Thanks.

Thank you, ladies and gentlemen, for participating in Crescent Point's first-quarter 2013 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.