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Executives

Scott Saxberg - President and CEO

Greg Tisdale - CFO

Trent Stangl - VP of Marketing & IR

Analysts

Cristina Lopez - Macquarie Capital Markets

Patrick Bryden - Scotiabank

Brian Kristjansen - Dundee Capital Market

Grant Hofer - Barclays

Travis Wood - TD Securities

Don Rawson - AltaCorp Capital

Crescent Pt Energy (CSCTF.PK) Q2 2013 Earnings Call August 8, 2013 12:00 PM ET

Operator

Good morning ladies and gentlemen, my name is Marcus and I will be your conference operator today. At this time, I would like to welcome everyone to Crescent Point Energy’s Second Quarter 2013 Conference Call. All lines have been placed on-mute to prevent any background noise. After the speakers’ remark, 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, but may not be recorded or rebroadcast without the expressed consent of Crescent Point Energy. 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, 2013 were announced this morning and are available on Crescent Point’s and SEDAR’s website at www.crescentpointenergy.com and on the SEDAR website.

During the call, management may make projection 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 to retentions to the forward-looking information and the non-GAAP measures sections 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.

Scott Saxberg

Thank you, operator. I would like to welcome everybody to our second quarter conference call for 2013. With me is Greg Tisdale, our Chief Financial Officer and Trent Stangl, our Vice President of Marketing & Investor Relations. I will give you an overview of some of our operational highlights from the quarter and then Greg will speak about the financial highlights.

We are happy to report that Crescent Point executed a record quarter for both production and cash flow. We set a new production record of more than a 117,700 BOEs per day weighted 91% to crude oil and liquids which was higher than our Q1 despite having budget for quarter-over-quarter decline due to expected impacts of spring breakup.

Our organic production growth during the quarter was driven by our successful drilling program particularly in Utah as well as continued success with our waterflood programs and a spring break-up that was less severe than expected. We are also pleased to report that we generated record cash flow of more than CAD500 million, 31% increase over second quarter of 2012 cash flow.

With these record results year-to-date, we have upwardly revised our guidance for production and cash flow for the year, while maintaining capital expenditures of CAD1.5 billion. We have increased our average daily production for 2013 by 3500 BOEs per day to 117,500 and our exit production rate by 2000 BOEs per day to 119,000. We have increased our cash flow guidance by CAD200 million to CAD2 billion. This represents the cash flow per share of CAD5.15 per share.

Our upwardly revised targets, conservative balance sheet and current commodity prices have all contributed to the strength of our balance sheet. Because of the strength we’ve decided to suspend the premium component of our drift effective in fourth quarter 2013. This will reduce the amount of equity raised through the program and of course it will not affect our monthly dividend which remains at CAD0.23 per share. Taking the drift change into account our balance sheet will stay strong as always and will continue to be disciplined in our capital spending and acquisition opportunities.

Looking closer at Q2, we grew production by more than 20,000 BOEs per day over second quarter 2012, showing continued per share growth, continued to actively hedge our production into the recent rally of WTI oil prices and the weaker Canadian dollar which help support our increased cash flow and delivered strong production growth in Utah where we drilled 27 net wells in second quarter with a 100% success rate and increased production to more than 10,000 BOEs per day, which is a 28% increase from the production required in Utah transaction.

We are pleased with our results in Uinta Basin, with wells continuing to perform at or above our initial expectations. We continue to test new completion techniques in the area and plan on implementing the 3-D seismic program covering a large portion of our operated lands in the Randlett area in fourth quarter 2013. During the quarter we continued to develop and grow our core Bakken and Shaunavon assets through development drilling or waterflood programs and the application of new technologies. We also continue to develop our rigging place including Beaverhill Lake rig and Three Forks North Dakota Bakken.

We continue to make big strides in our field-wide expansion of our waterflood programs. In the early second quarter we received a permit from the Government of Saskatchewan approving our first Lower Shaunavon waterflood unit. And subsequent to the quarter we received technical approval for the first of our four proposed Bakken waterflood units. These approvals are very significant milestones in the development of the waterflood programs in the Lower Shaunavon and the Bakken and reaffirmed their success today.

It’s worth noting that our independent engineers have completed preliminary studies on existing waterflood patterns within the Bakken and have found ultimate long term recovery factors upwards to 30% are achievable in those areas. These studies will be factored in their yearend reserve assessments wherever appropriate.

In May we began injecting water in to our first shared waterflood pilot in the Beaverhill Lake light oil resource play. We’re planning an application for a second Crescent Point operator waterflood pilot in Beaverhill Lake, which we expected to be operational in the first half of 2014.

Our capital expenditure budget remains at 1.5 billion for now, but we have the flexibility to increase this later in the year depending on commodity prices at our plants for 2014. For the remainder of the year, we are focused on developing a high quality asset base, on expanding our waterflood programs and on refining new technologies and techniques. We believe we’re in a great position so far in 2013 and we are well on track to meet our new targets.

Before handing things over to Greg, I’d like to thank all of our employees, our field staff, particularly our field staff in the Shaunavon area for their hard work in Q2 with breakup, and the Board of Directors for their hard work to develop and deliver another excellent quarter. We’re proud of what we’ve achieved so far this year, and look forward to another successful second half of the year.

Greg, we’ll now speak to the financial highlights.

Greg Tisdale

Thanks Scott. I’m pleased to report that Crescent Point generated record funds flow from operations of $504 million, or $1.31 per share in the second quarter. This represents 31% increase over the $386 million generated in the second quarter of 2012. Cash flow is driven by higher than expected production and continued high impacts of over $50 per boe in the quarter.

As a result of our strong production and cash flow results to-date, we’ve revised our 2013 annual guidance. Annual 2013 production has increased 117,500 boe per day from 114,000 barrels a day and correspondingly our funds flow from operations guidance has increased by 200 million to 2 billion or $5.15 per share for 2013.

On the treasury side in the second quarter we closed a product placement of long term debt in the form of senior guaranteed notes, raising $290 million U.S. and CAD10 million with attractive coupon rates ranging from 2.65% to 4.11%. In addition, renewed our credit facilities totaling 2.1 billion with the 2 billion syndicated portion maturing in June 2016. At the end of the quarter approximately 480 million was drawn on these facilities providing 1.6 billion unutilized, allowing a significant financial flexibility and liquidity.

In the quarter, we continue to take advantage of the (inaudible) and WTI oil prices and weaker Canadian dollar by actively increasingly our hedge portfolio. In the past three months we’ve added approximately 1,200 barrel a day of oil hedges in 2013 and 2014 to further lock in our increased cash flow guidance. We’re now 66% hedged for the balance of 2013, 52% for 2014, 28% for 2015 and 11% for 2016 on our oil production. In addition, we have hedged 18,000 barrels a day of fixed price differentials for the balance of 2013.

Given our strong financial position, continued operational success and current robust commodity pricing environment, we expect to reduce the amount of equity being issued under our dividend reinvestment program, effective fourth quarter with the suspension of the premium DRIP component. We will proactively manage our DRIP participation levels in future quarters to optimize our balance sheet and financial flexibility relative to short and long term acquisition opportunities and a higher rate of return building inventory. We remain disciplined in our approach to capital spending including our (inaudible) revised guidance for production and cash flow as well as our expected reduction of the DRIP, our balance sheet remains strong with projected net debt to cash flow approximately one times.

Given the strength of our balance sheet and hedge portfolio, we’re well positioned to continue to generate further strong operating and financial results for the balance of 2013 and beyond.

I’ll now hand things back over to Scott.

Scott Saxberg

Thanks Greg. We have an outstanding second quarter. We had record production and cash flow. We continue to see impressive results across our asset base, especially in Utah. And we have received key approvals for our waterflood programs. We’re in great shape and look forward to another successful year for our shareholders.

At this time, we’re ready to answer questions from the members of the investment community. So I’ll pass it back to the operator.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Your first question comes from the line 139 from Cristina Lopez from Macquarie. Your line is now open. Please go ahead.

Cristina Lopez - Macquarie Capital Markets

Just a couple of quick questions, one with respect to the DRIP and proactively managing the DRIP. Does that imply that you may end up capping the DRIP participation going forward?

Scott Saxberg

Yes, and basically we’re just saying that’s a tool that we have in our toolkit to use to either drop on or manage a little tighter. In the past years our levels were kind of at a reasonable level with kind of minor participation but in the last year or two it increased significantly. And so we felt the need that at this stage we don’t really need that cash and that we are pulling that back and we'll just manage that orders as depend on acquisitions or if we bump our CapEx or things just make it more optimizing a financial flexibility.

Cristina Lopez - Macquarie Capital Markets

Now with the waterfloods becoming a larger portion of your overall program, where do you estimate your current corporate declines are and going into 2014 what are you modeling or forecasting for corporate decline rates?

Unidentified Company Representative

We have been modeling pretty consistently like 33% sort of in our budget and in our five year plan and that’s conservative number, I think we are probably closer to 30 and we feel that over time, over the next three to four years that will sort of continually drop percentage-wise each year, so it’s hard to predict obviously out five years from that perspective but our view is that we will get it into the high-20s, mid-20s over the next four to five years.

Cristina Lopez - Macquarie Capital Markets

And last question with the railing of crude now in the Uinta Basin, what are you receiving pricing-wise relative to what’s you are receiving by just selling the barrels straight into Utah refineries.

Trent Stangl

The net backs on the rail stock is fairly consistent with the local market, I think well we've just gone through a Q2 with a lot of refinery turnaround, in the Salt Lake market, so generally speaking that market either on rail or in the local market was very soft during the quarter and we'll see both of those markets improved coming in Q2.

Operator

Your next question comes from Patrick Bryden from Scotiabank, your line is now open.

Patrick Bryden - Scotiabank

If I might, I want to zero in a little more on the tighter waterfloods, would you be willing to kind of hazard an estimate as to how much of those projects are impacting corporate decline rate today.

Unidentified Company Representative

Good question, I think in total in our company, I think we're at probably more than half our production is underwater flood through our various plays across in southeast of Saskatchewan and between (inaudible) and waterfloods drive to (inaudible). We are waterflood company being 90% oil weighted, I would expect almost all of our plays will be waterflooded at some point. On the Bakken side, we are saying loosely about 5,000 barrels a day right now and in the Shaunavon, it's probably 10,000 barrels a day probably.

Patrick Bryden - Scotiabank

Okay great and may be just dig a little deeper, would you kind of get the knot to the Bakken versus the Shaunavon performance wise, I am just curious what are the factors of success have been given you are dealing with different crude qualities and reservoirs there.

Unidentified Company Representative

On a straight recovery factor basis, the Bakken obviously being the lead oils are going to have higher recovery factors just inherently in that but on a relative performance from primary to waterflood recovery, they are very similar. So 4% to 7% on primary is going to turn into 15% in Shaunavon. With the results in Battrum and Cantuar and those fields have been around for over 50 years, they are upwards in the 35% to 50% recovery factor in their medium gravity crude and so I believe long-long term at the Shaunavon with the fracking that turns it into that conventional type reservoir and so we believe that the Shaunavon or at least I believe the Shaunavon is going to have even better recoveries than that 15%. But at this stage, we are seeing really strong, consistent operational response in the Shaunavon in majority of our patterns and similarly in the Bakken and so both of them I would say are pretty equally performing really well.

Patrick Bryden - Scotiabank

Great and then just any quick sense for the ratio of producers to injectors and response times that you would be expecting in those two plays?

Unidentified company Representative

Those are some of the things that we're experimenting on and so some of patterns are two injectors per section, some are four injectors per section, some are 400 meters into well distance, some are 200 meter into well and so those are the nuances, the things that we are dialing in on. If I was to say, based on our simulation work it’s going to be probably more like three wells per section in the Bakken, three injectors per section in the Bakken and in the Shaunavon its early days we are drilling down to eight well in fields and now we are now on our 16 well infield drilling pilot there and we are seeing positive results on the 16 wells per section infield so that could be similar to the Bakken it could be three injectors per section or it could be six to eight injectors per section depending if we go down to 16 wells per section. So pretty exciting stuff on the Shaunavon side with the infield drilling, that’s going to really dramatically improve recoveries there as well.

Patrick Bryden - Scotiabank

Can you maybe provide a sense, maybe it’s too early to do this but how you would anticipate the reserve assignments of credit peculating through the system, would it just be relative to the specific pilots or we’re going to see some extrapolation across your lands and what would the timing of that be as we look at ahead to year end.

Unidentified Company Representative

I think the importance of the unitization is that that now the reservoir engineers and the third party engineers look at these as units versus individual wells and so we’re going to get attended to get reserve bookings on a per unit basis versus a well by well basis and there’ll be a little bit more room to extrapolate from wells to patterns to the unit.

Obviously, we’re very early on these stages in all these units and even in the waterflood. So, we're anticipating we’ll get increase in recovery due to the waterflood on a significance level of our company of a 600 million barrel B plus B company is probably not going to be a huge magnitude relative to that size but relative to what we’ve seen in the past it will be significant, I would assume.

Operator

Your next question comes from Brian Kristjansen from Dundee Capital Market. Please go ahead your line is now open.

Brian Kristjansen - Dundee Capital Market

What are you currently forecasting guys for your Q4 participation rate once the premium piece falls off?

Unidentified Company Representative

It will be kind of about half, so we are around 70% and that will optic kind of mid to low 30s.

Brian Kristjansen - Dundee Capital Market

And can you comment on performance in Utah, it seems to be somewhat singled out in that strong organic growth particular in Utah. Can you comment on either IP 30 rates, you’re seeing on average or any commentary you can provide on the six well and multistage test.

Unidentified Company Representative

It’s really early days on the multi-test on the change in the frac technique, we really only have about a month of data on that stuff and we’re also drilling step outs from within our (inaudible) area as well top of that. But basically, the rates of returns that we expected when we went into the acquisition are falling pretty well in line, I think our low case stuff is average is like a 100,000 barrels per well and like 100 barrels days IPs or something like that to 200,000 barrels a day IPs and then our high case stuff is like a 170,000 barrels and those are pretty solid rate of return wells as well and so we’re seeing those kind of results we anticipate within around that area.

I think some of the misconceptions with different operators in there, we obviously are partnered with Bill Barrett with Newfield in the Bill Barrett case in particular we were AFE, I think 30 wells within the programs so far this year and we participated in 24 of those. The sixth that we didn’t participated in were ones we felt were riskier here and step out location. So, we’re pretty happy with the 24 wells that we participated in the results of those and that's part of our program obviously and the success Utah side. And that being said, it’s like less than 1% of our overall corporate production on the non-upside on that. Those are just sort of nuances I think that we kind of drilling down to level that we deal with.

Brian Kristjansen - Dundee Capital Market

Any comment your operated rig versus your non-op and where costs are and where you see them going in Utah?

Unidentified Company Representative

Our costs have been in line with what we’ve anticipated for the drills. I think one of the reasons why it’s probably more highlighted is we drilled out through Q2 in Utah because there really is no spring break up there. So, that’s partly speaking to the performance there, its direct year around access. So, we’ve had some positive results on the Newfield non-op side on the horizontals as they have disclosed and so I think as you can tell by our production growth I think it’s speaks volumes. The way to look at it, that we grew production by 30% in six months there. So, easy to operate, year around access, low risk infield drilling, just a solid area.

Trent Stangl

When you look at Utah in the context of our entire 2013 budget it’s 15% to 20% of the budge during Q2, it represented a half the wells that we drilled in the quarter and that’s kind of Scott mentioned, we can drill through there, through breakup, we didn’t really have those breakup impacts and that’s one of the reasons we want to highlight that area.

Operator

Your next question is from Grant Hofer from Barclays. Your line is now open.

Grant Hofer - Barclays

Can you or have you made any effort to quantify the impact of spring break up on the Q2 volumes.

Unidentified Company Representative

No, I don’t think we really asses that.

Trent Stangl

There is a lot of moving part to it and on the one hand we’ve drilled for two extra weeks in Q1 and so we went in Q2 really quite flushed out, which makes our Q2 look really quite strong relative to the rest of the year from a profiling point of view and then you’ve got of course the impact of not drilling for a couple of months and so you’re facing your declines. So, there is a lot of moving parts in there, but definitely the break up wasn’t as severe as we expected. We didn’t have the level of shot in that we had budgeted for, for sure.

Unidentified Company Representative

Yes, it was something, I think we budgeted something like 7,000 barrels to be coming off in the quarter and because of a lot of the capital we spent in the previous year on roads and just protecting the well sites because of the big flood event we had a couple of years ago, we really mitigated the impact of Q2, and so I think we had more or like 2000 barrels a day or 3000 barrels a day of shut in volumes through that time period.

The interesting shift for this year is that it’s been rainier obviously in June and July and in our budget and our original budget, we have our capital starting in July 1 and I think it was about four years ago where we went to that sort of just stopped fighting June weather and let start our capital program in July, and so this year is no different. We basically went for end of March all the way till the beginning of July without really much drilling activity other than in Utah and North Dakota, and so we’re just really two weeks into drilling program in Q3.

So, our production profile and our capital profile all weighted to the backend of Q3 and Q4 which allows us to keep that capital program at 1.5 billion but then we upwardly revised our production number and because of our performance in Q2 and Q1, and we’re going to outperform our Q3 relative to our original budget, and so that’s why we’re able to bump without bumping out capital.

Grant Hofer - Barclays

Thanks for that now, why would you guys want to see before you would consider lifting the CapEx, I mean, you had a couple I think a trio of $150 million wages that you’d contemplated at the outside of the year, what would give you cause to put those in the budget?

Unidentified Company Representative

Well, I think it’s mainly price and then we’re working away obviously we do projects within each of our core areas and then as we see results of those we will add to those programs, but it’s by enlarged to price and then right now we’re just starting to phase of our budgeting for 2014, so when we go through that phase, we tend to look at sort of November and December timeframes to set ourselves for 2014, so hence why sort of the discussion probably more like September and October we’ll have an understanding of our 2014 program and that may dovetail into backend of 2013 to combine, so a combination of that and price.

Grant Hofer - Barclays

On the rail side, can you talk about how much volume you shift in aggregate on rail in Q2 and whether that’s changing going forward just given what we’ve seen with differentials and the opportunity there?

Trent Stangl

We’ve got about 18,000 barrels a day of fixed contracts for the year so that’s kind of our base volume and then beyond that we can shift it around little based on where prices are at. We’ve always seen out net backs on our pipeline delivered volumes improve dramatically and this allows a little bit with WTI up and with FX little bit weaker, and differentials quite tight, and the rail and the piper really quite competitive in these markets, so we’ve got a little bit more on pipe and what we had in previous quarters.

And looking forward into Q4 here and later Q3, we'll see a little bit of widening in differential I think just due to normal seasonality and so probably I'll give more volumes on rail in the second half of the year.

Operator

(Operator Instructions) Your next question comes from Travis Wood from TD Securities. Your line is now open.

Travis Wood - TD Securities

Most of my questions have been answered so I guess I need to get quicker on the trigger but just heading back to the United States, given the growth that we saw in Q2 from Utah, do you expect the backend of this year to see falling production from that and where do you think Utah exit the year at and then just looking at the waterflood, what’s the timing of that and what do you think the process is to get that push through to get the approval for the waterflood across the basin in Utah?

Unidentified Company Representative

Just on the pressure side we’ve got basically one rig running consistently throughout the whole year, so I think our exit there combined for the U.S. is something like 15,000 barrels a day on the backend. So it’s relatively flat to the end of this year or whatever and on the waterflood side, we’re looking probably closer to late 2014 kind of timeframe for the regulatory side.

Travis Wood - TD Securities

So will it be in the regulatory hands for up to a year or will it be submitted in six months and then take six months for the turnaround?

Scott Saxberg

I would have to get back to you just on the timeline, but it's going to be a longer timeline like a full year probably by the time we get everything in place.

Operator

This question comes from Don Rawson from AltaCorp Capital. Your line is now open.

Don Rawson - AltaCorp Capital

I think my Utah question has mostly gone answered. one thing I was wondering about was you mentioned the netbacks in the quarter there were consistent on rail and then the Utah market. Just wondering what the recession has been there for oil on the East Coast? And do you think that differentials are narrow in Utah or through rail and the East Coast going forward?

Scott Saxberg

What was that again Don?

Don Rawson - AltaCorp Capital

Do you think differentials will narrow in Utah or in rail to the East Coast given some of the middle trial shipments that you had on Utah crude?

Scott Saxberg

I think for sure they will, it's still pretty early days for the rail right now, as we noted we only have a couple thousand barrels of our production on rail, which is relative to the 50,000 to 60,000 barrels a day of local production is not a big sort of dent in that local market. As I mentioned earlier there was a fair amount of refinery turnaround and so on during Q2. So I think as this year progresses we get our permanent site up and running. We get more barrels into different refineries so they can run them and get comfortable with the barrels. I think you will see those differentials improve.

Fighting against that little bit has been tightening of the brand and WTI spread. But I think when you look beyond sort of the Gulf Coast and East Coast and look along the West Coast, there is going to be some good opportunities for this.

Don Rawson - AltaCorp Capital

And the other question I had was just related to the budget, obviously haven't changed it yet. But conceptually if you added capital later in this year would it get spread around or there is certain areas that you think that you might want to emphasize and if you added incremental capital to this year's budget.

Scott Saxberg

We've got obviously tremendous amount of projects in all of our core areas, what I would look to be as probably more capital spent in the Bakken, in North Dakota and Southeast Saskatchewan and then little bit of another wedge in Utah and then additionally into some of our merging plays into Beaverhill Lake, Swan Hills at Viking. But pretty generally spread across we have got several different wedges that we created and developed to that. But again we're just in the mix of budget, starting the budget process and some of that will fold out through that budget.

Operator

We have no further questions registered at this moment. I would now like to turn the meeting back to Saxberg.

Scott Saxberg

Thank you very much. I would like to thank everybody for listening into our Q2 2013 conference call. And look forward to another great half of the year.

Operator

Ladies and gentleman for participating in Crescent Point Energy's second quarter 2013 conference call. If you have more questions you can call Crescent Point Investor Relations department at 1877-403-1678. Thank you and have a good day.

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