Mar 11, 2015
Executives
Scott Saxberg - President & CEO Neil Smith - COO Greg Tisdale - CFO
Analysts
Brian Kristjansen - Dundee Capital Markets Pavan Hoskote - Goldman Sachs Patrick Bryden - Scotiabank Gordon Tait - BMO Capital Markets
Operator
Good morning, ladies and gentlemen. My name is Mary and I will be your conference operator today.
At this time, I would like to welcome everyone to Crescent Point Energy Fourth Quarter And Year-End 2014 Conference Call. [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 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 and analysis for this period ending December 31, 2014 were announced this morning and are available on Crescent Point's website at www.crescentpointenergy.com and on the SEDAR and EDGAR websites.
During the call, management may make projections or other forward-looking statements regarding the 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, the EDGAR 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.
Scott Saxberg
Thank you, operator. I would like to welcome everybody to our fourth quarter, year-end conference call for 2014.
With me is Greg Tisdale, Chief Financial Officer; Neil Smith, Chief Operating Officer and Trent Stangl, Vice President of Marketing and Investor Relations. I'll give an overview of our quarterly results, Neil will discuss our operational highlights and Greg will speak to our financial highlights.
We're very happy to report that Crescent Point delivered an excellent quarter and year. We advanced all of our core areas with a strong capital program and several strategic consolidation acquisitions made throughout the year.
Our strong balance sheet, robust hedging program and industry-leading asset base have positioned us well to withstand this low oil price environment. Our company strategy is structured to guide the organization regardless of the state of commodity prices.
In 2014, we set a new production record of more than 140,000 BOEs per day and exited the year with a record production of more than 155,000 BOEs per day. We also grew production per share by approximately 8% over 2013, an increase of more than 20,000 BOEs per day.
Looking at the year as a whole, some key metric highlights our strong performance. We exited the year with debt to cash flow of 1.3 times, which is excellent given the current economic conditions.
We're in a strong financial position and we'll continue to protect the balance sheet and dividend. To further strengthen our financial position, we extended our syndicated bank line by 40% to a total of CAD3.6 billion of credit capacity subsequent to year end.
This significant addition of credit facilities provides us additional flexibility and is increasingly valuable in this low oil price environment. We also are well-hedged and currently have 56% of our oil production hedged for 2015, at an average price of approximately CAD89 a barrel and 33% production hedge for 2016.
We increased proved plus probable or 2P reserves by 22% to 807 million BOEs at year end. On a per share basis, this represents 7% for 2P reserves.
Excluding acquisitions, we added 97 million BOEs of 2P technical and developed reserves, the majority which are in our core Bakken, Torquay, Shaunavon and Uinta Basin reserves plays. This represents the 13th consecutive year of strong, positive technical and development reserve additions.
Since inception, we've cumulatively added over 500 million in 2P reserves through organic growth alone. For the second consecutive year, our reserve additions included reserves attributed to our Viewfield Bakken waterflood.
For 2015, we'll continue to place a strong emphasis on prudent cost and risk management. We have undertaken a concentrated effort to partner with our vendors to reduce costs as a result of the continuing low oil price environment.
We've been pleased with cost reductions realized to-date and we expect that further savings can be achieved. In addition to cost savings, we're also working hard to continue to increase upon our own efficiencies.
Given these initiatives, we maintain significant flexibility over the 2015 budget. We will review the budget again after spring breakup to determine allocation plans that best position us for 2016.
We believe that the steps we're taking to lower our cost structure and increase efficiencies will benefit the company in all price environments. We continue to develop several areas with significant growth potential.
In the Torquay play at Flat Lake, we continued to consolidate this billion barrel oil pool and we've seen positive results with our step-out wells as we have continued to delineate the play. This year we doubled our reserves in this area.
We're also excited about starting our operated horizontal drilling program in Uinta Basin resource play, targeting new zones such as the Douglas Creek. Horizontal drilling in the basin is in its infancy and we continue to be excited about the potential of the Uinta Basin as a growth engine for the company in years to come.
In our Viewfield Bakken and Shaunavon resource plays, we're encouraged with the implementation of a closed sliding sleeve during the fracking process. We've done 90 of these so far to-date.
The closed sleeve has the potential to increase the efficiency and the productivity of our waterfloods due to increased control over water displacement, which could lead to strong increases in recovery. It also has the potential to lower capital costs by reducing the frequency of well cleanouts caused by proppant flowing back into the well.
Crescent Point is unique in that we offer exciting, long-term growth potential through the development of our early stage Torquay and Uinta plays and stable cash flow from developed assets and technical efficiencies. We believe we're well positioned in the current environment and are continuing to maintain a conservative and flexible approach to our business and the development of our world-class asset base.
Before I hand things to Neil, I would like to thank all of our employees, including our field staff, executive team and our board of directors for their hard work in delivering another record year. Neil will now discuss operational highlights.
Neil?
Neil Smith
Great. Thanks, Scott.
During 2014, we achieved material reserve additions and increased our 2P reserves by 22% to 807 million BOEs. Of these additions, 97.1 million BOE reduced technical and development reserve additions, excluding acquisitions.
Since inception, we've added over 0.5 billion barrels of cumulative, positive reserve additions to organic growth alone. This represents the 13th consecutive year of strong, positive technical and development reserve additions.
We did this efficiently with finding and development costs of CAD21.59 per 2P BOE, excluding changes in future development capital, represents a recycle ratios of 2.4 times. Including changes in future development capital, our funding and development was just CAD22.11 per 2P BOE.
It is important to note that our future development capital does not include any of the cost reductions that are being implemented during this year. In regards to the fourth quarter, Crescent Point's record production of 153,800 BOEs a day was driven by our continued successful drilling program across our asset base and the ongoing success of our waterfloods and cemented liner completion techniques.
As Scott mentioned, in our Viewfield Bakken and Shaunavon resource plays, we recently started to implement a closable sliding sleeve during the fracking process. That, in combination with our waterflood, has the potential to increase recoveries and reduce capital costs overall.
Also, we continue to be excited about our Flat Lake Torquay discovery in Southern Saskatchewan and we've increased our book 2P reserves by over 90% in 2014 alone. In our Shaunavon play, we benefited from performance-based reserve additions attributed to the 25 stage cemented liner completion design, which we expect will become more material as the program advances.
Our waterflood program is contributing to our success in the play, with 38 active horizontal water injection wells currently operating. We continue to execute our Battrum and Cantuar drilling programs.
We assumed full operatorship of the Cantuar unit on September 1 and already we've increased production there by approximately 26%. Both of these assets continue to generate strong free cash flows.
We continued our drilling program in the Dodsland area in the Saskatchewan Viking play and drilled 19 net oil wells during the quarter, which is our largest in company history. We're very pleased with production to-date and the wells have been coming on production at or better than forecast rates.
In addition, we continue to be excited about our development and exploration in the Uinta Basin. Since entering the play in late 2012, we have increased booked 2P reserves by close to 60%.
We drilled 30 net oil wells during the quarter and continue to implement our operated horizontal drilling program in both the Uteland Butte and Douglas Creek zones. Production is expected to begin in these two initial wells during this quarter of 2015.
We also completed a 20 acre down spacing pilot in the area to test ultimate producing well density. We're encouraged with results to-date, as down spacing has the potential to significantly increase the operated inventory in the area.
We're also working very closely with our vendors and we consider them as our partners to reduce the capital and operating cost of our programs as we adjust to a CAD50 WTI operating environment. We need everyone to be healthy, our company and our vendors and are working to improve efficiencies to reduce our costs and those of our vendors.
Our assets are some of the best, most economic plays in North America and in fact, we believe that if we aren't drilling, no one is. We project cost savings between 15% to 20% on certain projects relative to 2014 and expect to further reduce costs throughout the year.
Before handing things to Greg, I'd also like to recognize and thank all of our employees, including our field staff across Canada and the U.S. for their hard work in delivering another excellent quarter and another excellent year.
Greg will now discuss the financial highlights. Greg.
Greg Tisdale
Great. Thanks, Neil.
We're very pleased to announce that subsequent to the quarter we increased our syndicated credit facility by 40% or CAD1 billion, bringing the company's total credit capacity to CAD3.6 billion. As of December 31, 2014 we had approximately CAD1.27 billion drawn on these facilities, which represents only 35% of current credit capacity.
This significant source of additional credit capacity provides substantial financial flexibility and liquidity for the coming year, which is increasingly important, given the current oil price environment that we're in. We remain committed to maintaining a financially strong organization with a conservative balance sheet.
Our strong balance sheet, combined with our low risk, high economic drilling inventory and disciplined hedging program positions us well to continue generating strong operating and financial results into the future. In the fourth quarter of 2014, we generated cash flow of CAD573 million or CAD1.28 per share.
This represents a 7% increase over the CAD533 million generated in the fourth quarter of 2013, despite a 15% decline in average selling prices. On an annual basis, in 2014 we generated over CAD2.4 billion of cash flow, providing an 18% increase over 2013 as we continue to add shareholder value.
Funds flow from operations was driven by strong operating netbacks prior to realized derivatives of CAD52.43 per barrel. We maintained our consistent monthly dividend of CAD0.23 per share, which equates to a yield of 8.8% based on our average Q4 share price of CAD31.29.
Since inception, Crescent Point has paid more than CAD5.9 billion in dividends and remains committed to its dividend and growth strategy to provide value to our shareholders. Based on results to-date, we're maintaining our annual production guidance of 152,500 BOE a day and capital expenditure budget of CAD1.45 billion.
With the weaker Canadian dollar and contango in the forward oil curve, we continue to be disciplined and layer in hedges. We have been targeting CAD80 price levels through the forward strip.
Currently for 2015, we're 56% hedged at an average price of approximately CAD89 per BOE. Looking beyond this year, we're now 33% hedged for 2016 at an average price of approximately CAD84 BOE and we also have hedges in the books through to mid-2018.
I'm going to now hand things back over to Scott. Thanks.
Scott Saxberg
Thanks, Greg. We've had a great year and look forward to the rest of 2015.
I think some of the major points, just to reiterate, that we had a strong production growth and exit this year, we're financially well-positioned, a CAD1 billion line increase. We're well hedged, 56%, our Torquay play is expanding; we doubled our reserves there.
Our horizontal drilling in Uinta, we're just starting testing new zones, pretty excited about that. We had increase of 60% to reserves in the Uinta since our acquisition.
And then one of the things that excites me the most, I think, overall from being a reservoir engineer is the new technology in the closable sliding sleeves that will enhance our waterflood recoveries and continue the growth of both our Viewfield and Shaunavon fields throughout the coming years. And then I think just in general, we're going to be very flexible with our budget and prudent on our spending and continue to drive down costs for the year.
So, despite current weaknesses in commodity prices, we want to reiterate how well-positioned we're and our business model is well-suited to continue to create value during this current environment. At this point, we're ready to answer questions from the members of our investment community.
So I'll pass it back to the operator.
Operator
[Operator Instructions]. Your first question comes from the line of Brian Kristjansen from Dundee Capital Markets.
Please go ahead.
Brian Kristjansen
Can you comment on the technical revisions to your probables? Was that all category changes to proved or have any of your spool curves been adjusted?
Neil Smith
It's a bit of both, Brian. It's kind of spread across all three.
There is some category shifts, yes.
Brian Kristjansen
Anything material on curves on any play in particular?
Neil Smith
No. Last year we did our big bump up because of the cemented liners.
You saw our infills in Viewfield go from 75 to 100 and a lot of our other properties followed suit. Sproule had the two or three years of history that they need under NI 51-101 to make that adjustment.
Brian Kristjansen
Okay. Anything in particular you can point to with respect to the higher development capital in the year relative to the CAD2 billion budgeted?
Neil Smith
A lot of the budget that we typically do, we make a decision around November, whether we're going to carry on going through setting ourselves up for January. So some of that, it's 5% on the total, we're just a bigger company now.
Some of that is just carrying our momentum going into the Christmas holiday break.
Greg Tisdale
Some of it is carried from the year before, so you look on both sides of the year where that capital gets spent, so it's across a lot of our plays.
Operator
Your next question comes from Pavan Hoskote from Goldman Sachs. Your line is now open.
Pavan Hoskote
Following up on your comments on waterfloods, clearly a lot of progress with lower decline rates and the independent reserve engineer validation as well. Now, given that you're going ahead with your waterfloods program, despite the low oil prices, can you please give us the updated targets in terms of economics for your waterflood program and how that compares with economics for your primary drilling in the Viewfield Bakken and Shaunavon plays?
Scott Saxberg
Well the economics on the waterflood, on a cost basis it's CAD2 a barrel. So the cheapest barrels we can add is through waterflooding.
What I'm really excited about is with the closable sliding sleeves, what it allows you to do is move water around the reservoir, move water to different fractures within the wellbore. So if we have 25 fracs in one wellbore, we could go in very easily with coiled tubing unit and close off five or six sleeves and divert water from the injector to different parts of the offsetting wells or on a producer, go in and shut down the toe or the heel or in the mid-part of the wellbore and divert the water production from those wells.
So what you have now is in each of these sections where we have four horizontal waterflood injectors and four producers with 25 fracs each, that's equivalent to 200 wellbores within a section that we can go in individually and close off each individual sleeve and alter the pattern and how we move water around. It's a huge, huge technical advantage and technical change that completely allows us control over how we waterflood and where we put water, which will increase recovery factors significantly in both fields.
We've done 90 of these so far, so it's not like we've done a couple and we've done it for about a year. We're very excited about that change and the cost is lower cost on top of that because we don't get the sand flow back.
After we do a frac, you close the sleeve then you do the next frac, close the sleeve. When you're done, you go back and open up all the sleeves, but by that time all the fracs have healed and it allows for the sand not to flow back into the wellbore and therefore we don't have to clean out the wells and we get full response out of using all the sand that we have pumped into the wells.
So it's a huge technical change that is very positive for both the Shaunavon and Bakken fields.
Pavan Hoskote
My follow-up is on M&A. Given the move in commodity prices and the more recent move up in oil and gas equities, any color in terms of what you are seeing in the M&A market?
Scott Saxberg
There are lots of, I would say right now, lots of discussions with different parties and people. I think from our perspective, we're very patient and looking for opportunities that number one, improve the company on a strategic basis and on an asset consolidation basis.
And then financially, we want to better the company and improve our financial position. So we're being very selective and prudent and opportunistic and being patient through this time.
Thank you.
Operator
Your next question comes from Patrick Bryden from Scotiabank. Your line is now open.
Patrick Bryden
I'm just curious on the closable sliding sleeve; it looks like a year now with about 90 wells you'd mentioned. Do you have a sense that you can provide in terms of how much that might still be in the primary phase versus others that you've tested on an injection phase?
Scott Saxberg
I think we've basically dovetailed it into our drilling program. So I couldn't tell you right off -- most of those, a good chunk of them have been in the Shaunavon area with that drilling program.
And then we've done about 30 or more I think in Viewfield. We started with the closable sleeves earlier, but we weren't able to use -- we didn't have the technology at the time to close the sleeves while we were fracking at that time.
There's actually more wellbores with that system in it that we can now go back to as well. But we're just dovetailing it in to our drilling program.
Patrick Bryden
Okay, understood. From the standpoint of just obtaining pressure versus actually controlling movement of the water, you are optimistic that you can actually move oil banks around that kind of thing?
Scott Saxberg
Well we've got examples where we had -- a great example is one horizontal well that we had offsetting the original injector from Wave in the Shaunavon field and it was a well that had watered out after about a month, as soon as they turned the injector on. So Wave had shut it in and it was shut in for about a year and then when we had taken it over, we put it back on production.
It was like 99% water cut, 500 barrels a day fluid or something. It was not an economic well.
And we went into that wellbore, packered off the toe of the well and put it back on and it came back on this year or mid last year around 200 barrels a day of oil and high oil cut. And it demonstrates what the closable sliding sleeves can do to the movement of the water in the reservoir.
So we're pretty excited about that.
Patrick Bryden
And then more broadly on the water flood reserve assignments that you've received, it's good to see. Do you have a sense for or some insight into the pace of those bookings?
Is that on track with what your expectations would have been?
Scott Saxberg
Yes, they're on track. You've got to remember we're very early days in even the primary drilling of these fields.
We still have eight years of drilling inventory just to drill up these fields on primary in the Bakken. I think it's ten years or something in the Shaunavon.
So the reservoir engineers aren't going to give us waterflood reserves until we start getting closer to the primary recovery on the reserves. When you think about we're only booked about 3% or 4% in general in some of these fields or parts of the field.
And so as we add more injectors and those producers start outperforming their curve, which we've seen everywhere we've put an injector, you'll start to see those adds. And they'll slowly, as you're seeing now, accumulate and get larger and larger and become a bigger and bigger component of our reserve adds every year.
I think we're probably two or three years away from seeing large reserves numbers. But in context, I think we've added 7 million or 8 million barrels of reserves through the waterflood, which is pretty significant.
Those are in the core areas where we've been waterflooding for four or five years. So I think generally, we're pretty pleased with how things are progressing and we're adding more injectors and as we add more injectors, we can add more reserves.
Patrick Bryden
So technically, it's progressing well. Any comment on how you perceive the moderation of decline over the next few years?
Scott Saxberg
Yes, again we're also growing the primary at the same time. We've seen 8% to 10% reduction in decline trend so far in the major fields.
And every time we update the base waterflood numbers, the declines are getting shallower and shallower. So we're pretty positive on how everything's working from that perspective.
Patrick Bryden
A couple of quick questions on the Uinta. You've had a nice uptick in reserves there.
Can you may be elaborate on the factors behind that increase?
Neil Smith
Most of it comes from our step out drilling within the Randlett area. We had a lot of reserve adds to the northwest area of Randlett and into the southeast extension of Randlett, so basically following up on our step-out program.
It's not really a step-out, in a sense. We're in the middle of this huge, huge field and we're basically joining the north Uteland Butte field and the south field and proving up that both that it's all one big field, so pretty low risk step-out drilling.
And we expect to add significant reserves there again in the next several years, just continuing those programs, pushing out to the east in Aurora where Ultra bought or whatever. We've got quite a bit of land that stretches out east to them.
We're going to be drilling step-out wells there this year that will prove up a whole bunch of reserves out onto the east side and so continuing that program.
Patrick Bryden
And as you push forward the horizontals and the waterflood, are there any key markers we should be looking for? It looks like you're looking ahead, some production information in Q1.
Anything we should look for in terms of catalysts?
Neil Smith
In Utah or just in general?
Patrick Bryden
In Utah as you are pushing ahead with more horizontal testing and implementation of waterflood long term.
Neil Smith
We just started our horizontal program. I think we're on well three, so not a lot of data is going to come out in Q1 relative to that at this stage other than the new zones we've tested, the Douglas Creek, I think which will be exciting from our perspective.
I think as we step through the year and test newer zones that have never been drilled horizontally. I think that's probably the key elements that you're going to want to look for.
Operator
[Operator Instructions]. Your next question comes from Gordon Tait from BMO Capital Markets.
Your line is now open.
Gordon Tait
To follow-up a bit on the decline rate, two parts to this question. I think you drilled 690 net wells last year.
Approximately how many do you plan to drill this year?
Neil Smith
About 616, 617 wells in our budget.
Gordon Tait
So almost the same number of wells drilled, but with more -- okay. I thought you would have fewer wells under IP rates with the clients.
How you see your overall corporate decline rate changing this year? Do you see much impact from the waterflood yet or should we still model in what you've been using in prior years?
Greg Tisdale
I think we've been using 33% or something like that. I would expect, when we ever look at our five year model and we pull back our capital the way that we have on the lower price scenarios, what you will see is a 2% to 3% drop in decline rate excluding waterflood results.
I would expect, as we're adding more waterflood, the waterflood's catching up with -- now that our growth profile in the lower price environment is lower with a lower decline. There should be a combination of lower decline with that, so I would use 1% to 2% to be conservative from where we're at.
In that 29% to 31% range is what we would anticipate.
Scott Saxberg
On the well count, you've got to be careful because if we move some more drilling over to the Viking, those are cheaper, lower rate wells that add to the well count that don't really relate only to what you are trying to calculate on.
Gordon Tait
I think you're saying you're budgeting 15% to 20% cost reductions, but is there room to negotiate that higher in certain areas?
Scott Saxberg
Yes and we've seen that in individual pieces of our business. What we're wanting to see now, we need time and history over the year to see the total effect.
In our budget's already a 10% drop and then we're going to look at how that's going to affect us for the rest of the year and whether we either put that money back in and drill more wells with the savings or just take those savings, depending on where commodity prices go. But we've seen a pretty good reasonable discount or drop across the board, all of our fields and all the assorted pieces of our business including operating expense and capital.
Neil Smith
The other thing, Gordon, that we're stressing as well, what's as important to me for dropping our costs, is improving efficiencies. The example that we've used over time; when we first got into the Shaunavon, it was 14 days to drill a well, now it's 6 to 7.
We're spending a lot of time with our vendors, not only helping them dissect their supply chain to go up it to help them to drop costs, but more to me, is improving the efficiencies because those endure through CAD50 or CAD100 WTI pricing. It's not just saying to our vendors, cut 30% and do it now.
It's working closely with them to get improved efficiencies. I would be happy if 20% was improved efficiencies and 10% was a cost cut, but the bottom line is we have to see those numbers.
We're just in a different operating cost environment now.
Gordon Tait
Okay. Turning to expansion or acquisition opportunities, there are of course a few distressed companies operating in your core areas, so two questions.
How would you prioritize the areas in which you would like to expand if you could? Secondly, if it does involve distressed companies, how would you handle that debt that might come involved with that?
Scott Saxberg
I think, obviously our core areas where we want to consolidate are the lowest risk and easiest to implement and to bring in house. For our perspective, how we look at things, it's all on a relative basis.
In this price environment, obviously values and the valuations of those assets are going to drop substantially. And then relative to where our share price has gone, we want to capture and be prudent in how we approach those acquisitions so that they're accretive on a transaction basis and not step into something that's expensive that could hurt us.
So we're very cautious on looking at companies and opportunities that will improve our asset base and at the same time improve us financially. We're trying to figure out ways to do that in this environment.
Gordon Tait
Okay and then are there any new areas you would like if you had the opportunity to expand into?
Scott Saxberg
I think we've always said to people that Colorado, DJ basin is an area of interest. We have some land there.
It's early, early days that we've been in there for probably about a year now, trying to understand that basin. But generally we're and especially in this environment, we're staying very focused to our core Shaunavon, Bakken, Viking, North Dakota, Utah areas and again being patient with those opportunities.
Operator
Thank you. There are no further questions registered at this time.
I would now like to turn the meeting back over to Mr. Saxberg.
Scott Saxberg
Great. Thank you very much and we look forward to the rest of 2015 and beyond.
Operator
Thank you, ladies and gentlemen for participating in Crescent Point Energy's fourth quarter 2014 conference call. If you have more questions, you can call Crescent Point's Investor Relations department at 1-855-767-6923.
Thank you and have a good day.