Obsidian Energy Ltd (OBE) 2011 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Penn West Exploration First Quarter 2011 Conference Call.

I would now like to turn the Meeting over to Mr. Andrew -- Mr. Andrews, CEO of Penn West Exploration. Please, go ahead.

Thank you, and good morning. Welcome to Penn West's 2011 First Quarter Financial and Operating Results Conference Call.

With me this morning in Calgary is our President and COO, Murray Nunns; our executive team of Hilary Foulkes and Dave Middleton, our two executive Vice Presidents; as well as our Chief Financial Officer, Todd Takeyasu; and we have other members of the senior management team in the room with us this morning as well.

I am so very pleased to be able to join our management team this morning in our first conference call of Penn West Exploration. It's been a -- it's been a long time.

Over the past 3 years, through the worst economic times in 70 years, our team has worked hard and we've worked smart to position the Company for today and to prepare a new Penn West for the future.

I'm not going to talk about the past anymore. Instead, we'll focus on current results and what I believe is our very bright future. We believe that Penn West holds the premier position on light and medium crude oil resource plays in Canada with a stronger position than most of our peer group in the Alberta oilsands and an excellence portfolio of gas resource plays.

With the exception of the oilsands plays, which will primarily be a thermal application, the technology being used to create value from our resource plays is still in its infancy in Canada.

The proved methods of drilling horizontal wells quicker, cheaper and more accurately combined with technologies -- technology that lets us stimulate many more times the volume of hydrocarbon-rich rock than vertical technology allowed has brought a step change to western Canada.

To date, we have successfully implemented horizontal, multi-stage technology in light oil in the Spearfish in Southern Manitoba and the Colorado Viking in the southern borderlands of Alberta and Saskatchewan, in the large Cardium pool in central Alberta and in the red-hot shelf carbonate play in the Swan Hills-Red Earth area of northern Alberta.

On the gas front, we continue to aggressively delineate our large shale gas play in the Cordova Embayment of Northern BC. That's a complement to [Daltman Gas] drilling in the Montney and Colorado zones.

In mid-April, we commenced steam injection at the Peace River Oil project's first thermal evaluation. Well, all in all, I'd say not bad for a company that some have called sleepy in the past.

In addition to our aggressive exploration and development program, we continue to do the type of small acquisition and disposition deals that are focusing on strengthening our play portfolio.

During the quarter, for example, we worked through a number of deals that have increased core positions with funding comes -- coming from selective non-core dispositions.

In summation, what I'm trying to say is that I believe we've turned the corner and we've turned it hard, and we're emerging with a very good head of steam for the rest of the year and for the future quarters ahead.

Some regulatory stuff, Penn West Exploration are traded both on the New Stock Exchange under the symbol, PWE, and the Toronto Stock Exchange under the symbol, PWT.

All references during this conference call are in Canadian dollars unless otherwise indicated and all conversions of natural gas to barrels of oil equivalent are done a six-to-one conversion ratio. All financials are reported under the International Financial Reporting Standards, the IFRS.

Certain information regarding Penn West and the transaction results discussed during this conference call, including managements' assessment of future plans and operations may constitute forward-looking statements under applicable securities laws and necessarily involve risks.

Participants are directed to Penn West's First Quarter News Release that went out very early this morning and are also asked to review the advisory notice therein. Participants are also cautioned that the included list of risk factors is not exhaustive.

For additional information on these other risk factors that could affect Penn West's operations or financial results are included in reports on file with Canadian and US securities regulatory authority and may be accessed through the SEDAR website. That's at www.sedar -- S-E-D-A-R.com, or the SEC website at www.sec.gov, or at our own website. And we certainly welcome many visitors to the website.

I think for a sophisticated investor or for many of our retail investors, that's information that we have for you, including our most up-to-date presentation will be found at www.pennwest.com.

During this conference, certain references to non-GAAP terms may be made. Participants are directed to Penn West's MD&A and financial statements, which are available on our website, as well as filings available on the websites noted earlier to review disclosure concerning IFRS items.

Murray Nunns will guide you through the first quarter and then provide you with an update on our light-oil-focused plays in western Canada. We're going to give the call a little twist this morning as well.

Following Murray's review, Hilary Foulkes will give an update on the joint venture resource project, our exploration program and also some of the work that we're doing on portfolio management.

Then we'd like to open up the phones, at which time we'd be pleased to answer your questions. So without further ado, I'm going to turn the call over to our President and COO, Murray Nunns.

Super. Thanks, Bill. As you're well aware, we converted to an A&P on January 1, and since then we've been actively developing and appraising our assets. We've continued on and accelerated on the programs that we started in 2010.

We planned on executing a large-scale program in early 2011, which was double the size of Q1 2010 and we did. Our focus on crude oil, along with increased oil pricing, has resulted in strong Q1 cash flow. Our productive capability is where we want to see it at at the end of Q1. We have been doing this against a backdrop of changing key factors in the energy space.

The horizontal fracturing revolution has shifted activity in western Canada sharply away from dry natural gas and towards the light oil end of the spectrum. This has been accelerated by the rising crude oil -- rising price of crude oil.

A positive from the shift to the liquid side of the boat is the speed of with which the industry has embraced the application for the new technologies and the learnings that have come from that. Conversely, this has greatly increased equipment utilization in the Basin and will likely continue to drive costs upward from the service providers.

With the scale of our resource plays and the fact we are driving towards a greater portion of development activity in light oil, Penn West is as well positioned as any in the industry to sustain profitability through all parts of the commodity cycle.

Taking a quick look at production in the first -- or just touching on -- sorry. Just give me about a second here. I'll get this in the right order. Just on a couple of financial levels, the funds flow for the quarter was $356 million, or $0.77 per share. This compares with $0.67 per share, or $305 million, in the fourth quarter of 2010.

The net income for Q1 totaled approximately $291 million, or $0.63 per share. This compares with a net loss of $37 million, or $0.08 per share, in Q4 of 2010. This increase in earnings came as a result of higher oil and natural gas revenues and a deferred income tax recovery.

Now looking at production, in the first quarter of 2010 we averaged 166,100 BOE per day despite having approximately 3,500 BOE per day off line. The 3,500 BOE per day off line was driven primarily by two factors, an interruption at a partner-operated facility and a portion on one of the major oil transportation pipelines.

The winter was long, very cold and we'll testify to that, and western Canada received more snow than in recent memory. This was a tough winter for operations. Despite these conditions, we worked through an extensive tie-in program and carried on winter operations into early April.

In the first quarter, more than 70% of our wells brought on stream were from the Colorado Viking play and the Spearfish, or Waskada, play, shallow oil plays, I mean these are shallow oil plays. This -- these averaged first-month rates of 80 and 120 barrels respectively.

Over the balance of the year, our program shifts to a greater proportion of higher productivity wells from the Cardium and northern Carbonates play trends, and that's an important point to note in terms of the evolution of our overall program.

We are now into spring breakup, and our production focus is shifting to normal Q2 activities such as facility turnarounds and improving throughput. Based on our Q1 program, we entered the second quarter with productive capability of approximately 172,000 BOE per day.

Crude oil and liquids production now makes up roughly 63% of our production base. Just to underscore the impact that our oil resource plays are having on our production base, Q1 2010 we were producing approximately 76,000 barrels of light oil and NGLs per day. A year later, Q1 2011, we produce approximately 87,000 barrels of light oil and NGLs a day. This is a trend that's going to continue.

Now moving on to operational highlights, the first quarter of 2011 was positive for Penn West as we deployed as many as 35 rigs into the field. The Q1 capital program was focused on our four light oil plays. Approximately 75% of our drilling in the first quarter was single-well appraisals and 25% of our drilling was development-style projects.

Our aim was to continue our appraisal work on the Cardium and Carbonates and to push into the development phase at the Spearfish and portions of the Colorado trend. We executed on the program we planned, and we were pleased with the results from all four trends to date.

As we move forward in 2011, we anticipate much greater focus on development-style drilling. By year-end, we are targeting a shift to 75% development drilling and 25% appraisal drilling. We will increase the amount of pad drilling as this is fundamental to capturing costs and operational efficiencies associated with large-scale projects.

Over the balance of 2011, as we've said, there will be greater emphasis on the Cardium and Carbonate projects as we move them into the development phases. These projects have the capability of delivering significant volumes.

So, let's take a quick look at the plays. We'll start with the Cardium. In the Cardium, we had an average of 8 rigs running throughout the first quarter and drilled 34 wells in select areas of this play, and we'll just touch on a couple of these and give you a little bit of a highlight package.

At Willesden Green, the average total measured depth is about 3,100 meters. First-month average production for wells brought on stream in Q1 was about 250 BOE per day. That's an average first-month rate.

This is one of the key focus areas as we transition to an increase in development drilling. And just a small indicator of that, even through this breakup we have activity ongoing on an 8-well pad, which is being drilled through spring breakup, and we'll commence completion activities late Q2, mid Q3 is the current timeframe.

At Alder Flats, another area where we had had limited activity before this quarter, we drilled 10 wells and brought 6 on before breakup. The estimated first-month average rate, based on tests, is 225 BOE per day.

We have brought on a new well on stream in the last 3 weeks, which is averaging 430 BOE per day. This will be another area of near-term focus for our development program, and we have substantial holdings here with -- for which to build out on.

In West Pembina, we drilled 10 wells. Six of those wells were on production before breakup. First-month average for typical rigs in the area, or wells in the area, were being brought on stream, we'll be about 175 BOE per day.

In East Pembina, we also brought 8 wells on in the first quarter. The first-month average production rates for wells brought on stream in Q1 was 135 BOE per day.

We have enough appraisal drilling to date to understand the key variables in reservoir performance in the Cardium trend. We have also refined some of the -- some of the efficiencies in drilling and completions.

Penn West wells across the trend are averaging 220 BOE per day in the first month of production, 150 BOE per day over the first 3 months' production and over 100 BOE per day in the first year. There are solid economics in all portions of the Cardium trends.

Development plans for the remainder of the year will have us focusing on Willesden Green, Alder Flats and West Pembina. We anticipate having 5 to 7 rigs running for the rest of 2011, drilling 50 to 70 wells in total.

Now turning to the northern Carbonates, we drilled 16 wells and brought 12 on stream prior to breakup. We are still drilling largely appraisal wells in the Carbonate trend with encouraging results. Penn West is honing both the interpretation and operational techniques for attacking this type of reservoir.

Looking at the Slave Point, we drilled 12 wells during Q1, including the first dual-leg well drilled on this portion of the trend. The single-leg first-well average production rates for wells brought on stream in Q1 were 200 -- was 250 BOE per day. The dual-leg well produced a first-month average of 450 BOE per day, a very encouraging result.

At Swan Hills, 4 wells were drilled during the first quarter in a combination of both East and South Swan Hills. We are currently drilling a 4-well pad through spring break-up at Swan Hills. Our most recent platform wells averaged first-month's production rates of 325 BOE per day.

We anticipate operating 4 to 5 rigs for the balance of the year with another 20 to 30 wells planned. We will be development pad drilling in the Slave Point as well and doing further testing of dual-leg applications. We believe this is one significant cost efficiency that can be captured on this play trend in particular.

Now looking at the Spearfish of Waskada, drilling into the Spearfish formation of Southern Manitoba, which we've been achieving consistent results. We have ramped up production from high -- 500 BOE per day in 2009 to just over 7,000 BOE per day at the end of the first quarter.

On the Spearfish, we have transitioned largely from appraisal drilling to development drilling now. First-month's production rates have averaged 120 BOE per day. Three-month production rates have averaged 90 to -- 90 BOE per day. We anticipate operating 3 rigs starting in Q3, drilling another 30 to 35 wells over the balance of the year.

Looking at the Colorado group, the Viking formation in particular in this portion of it, the Colorado is a -- [E] is a very broad trend, and we've largely dealt with in the past just the oily portion of the trend. We're going to broaden that in the discussion today.

This trend extends from Southwest Saskatchewan to significant portions of Eastern Alberta. Penn West holds more than 750,000 net acres where we have identified now 2,500 locations in total. The Saskatchewan portion of the trend is dominated by light oil, whereas the Alberta portion of the trend is gas prone with considerable associated light oil.

And just walking through some of the highlights on the trend, in the Dodsland area of Saskatchewan development drilling, we drilled a total of 32 wells in the first quarter. In Kerrobert, Saskatchewan, we drilled 6 successful appraisal wells. Both areas produced first-month average rates in -- of approximately 80 barrels -- 80 BOE per day.

Appraisal work on the Alberta portion of the trend has identified several significant accumulations of higher-productivity gassy oil wells, which we will follow up in Q3 of this year. We have a two -- we have 2 rigs operations here after breakup and drilling, we plan approximately 30 to 40 wells in this program.

So, what are the key takeaways when we look at all of these four light oil plays? Results to date across our four major resource plays have been in line with our expectations and have served to further verify our production-type curve -- type curves, our estimated reserves and the structure of our capital plan for 2011.

In the first quarter, we drilled 129 successful resource wells. By late Q2 or early Q3, depending on service conditions, we will be drilling ahead with 15 to 20 rigs.

Increasing the application of pad drilling across areas such as the Cardium, such as Willesden Green, West Pembina and Alder Flats and the drilling of multilateral wells in select areas of the Carbonates will help Penn West to improve efficiencies and reduce costs as we drive to large-scale development.

I'd now like to turn the call over to Hilary Foulkes, our Executive Vice President of Business Development, and also one of the key authors of our joint ventures that we entered into last year. Hilary will provide an update on our joint venture resource plays, exploration and portfolio management.

Thank you, Murray, and good morning. As you know, last year Penn West entered into significant joint ventures on two early-stage resource plays, the Peace River oil partnership and the Cordova joint venture.

In the future of our oil partnership, we moved forward with our resource assessment strategy, which included the drilling of 53 stratigraphic test wells and 4 horizontal assessment wells.

Early in Q2, we initiated a steam injection on our first thermal pilot at [CL Gain]. With the Cordova shale gas joint venture, Penn West and its partner continued appraisal drilling in the first quarter. We will keep a drilling rig running throughout the balance of the year, and completions should start in the third quarter.

On the exploration front, we have definitely put the E back in exploration. Our group has been actively assessing emerging plays to which we have exposure through 6 million acres of land, and we have selectively added to these exploration positions through both Crown land sales and acquisitions. We will be testing several of these [trade] concepts over the course of the year.

Active portfolio management supports our business, and we will continue to consolidate around key positions while we simultaneously rationalize non-core assets. This strategy has a huge impact. It provides greater ownership concentration, greater costs and operational efficiencies and, ultimately, a greater corporate focus.

In closing, you've heard this before but we'll say it again, we are full-bore ahead in 2011 on executing an exciting growth strategy. We believe now, more than ever, in the quality of our plays and the ability of our people to deliver profitable growth for our shareholders.

Just before we take some calls, I'd like to let you know that in addition to Bill Andrew, Murray Nunns and Todd Takeyasu, joining us are a number of Penn West senior management team.

This morning, we have with us Dave Middleton, Executive Vice President, Managing Director of Peace River Oil Partnerships; Mark Fitzgerald, Senior Vice President - Production; Thane Jensen, Senior Vice President - Operations Engineering; Keith Luft, General Counsel, Senior Vice President of Stakeholder Relations; Bob Shepherd, Senior Vice President - Exploration and Development; Dave Sterna, Vice President - Marketing; Jeff Kearns, Vice President - Accounting and Reporting; and Jason Fleury, our Senior Manager - Investor Relations.

I'd like now to turn the call over to the operator and open up the phone lines to callers.

Thank you. We will now take questions from your telephone lines. (Operator Instructions). Thank you for your patience. The first question is from Gordon Tait with BMO Capital Markets. Please go ahead.

Good morning. I just wanted to -- I just have a couple of questions for you. You noted that the end of Q1, you're producing about 172,000 barrels a day, but it has been a wet, long, cold winter, long spring breakup. Is that going to affect your Q2? Are you going to be able to hold that through Q2? Or will you be delayed in some areas?

We're going to -- I'll take it over, Murray. We're going to work like hell to hold it. We -- Q2 is the time we have to do some scheduled down time. We've gone through the first major scheduled turnaround, which is at Crimson Lake, to give you an idea of what Mark's got people are doing in the field.

We did it not only in less time than we thought, we thought we did a much more thorough job and a very large plant at Crimson Lake that's back on stream right now. And Mark is pushing through as much of this as we can.

We're continuing to work in as many areas as we can through breakup with some of the paths that we put in place in the first quarter. Things are drying out very well.

I was talking to Zane and Mark, both, and having been out in eastern Alberta and southwestern Saskatchewan last week, I can, I guess, speak from experience that things are going up in the country. That will give us a little bit of a kick start. The -- Manitoba is experiencing some floods, but our plan was to get most of that work into the first quarter because of what we experienced last year.

We expect to get into the Cardium boat on time. The Cardium is always a little late in the quarter. So we're sticking to our guns and we're going to get the quarter off.

Okay. And then just on the pad drilling, I think it's in your press release, you drill about 90 wells in the Cardium this year, so like what percentage of those would be from pads?

I'd generally say, on the first quarter, less than 305 of our program we've been on pads.

Yes.

In the Cardium. They would have been single-well appraisals, testing out areas of the play. I think that over the balance of the year, by the end of the year, we want to be at 75% development at least. So effectively, a large portion of the program here on out will be pad drilling.

And so that really shortens your drill time, the rig move costs, all those things? So capital efficiencies, what kind of an increase in capital efficiencies do you see with those -- with that drilling?

Okay. What we'd hope to achieve under normal circumstances would be 20%, as long as our friends in the service sector aren't working their books. And I'm sure they are this morning, to bring their price guys up. But if prices are static, we believe there's at least 20% efficiency to be gained. That's the plus side.

One of the sides -- one of the other sides we have to look at there's a bit longer cycle time. Because you can't be drilling and completing on a lot of these pads simultaneously. So your production adds tend to get a little bit lumpier. That's one of the other results from this activity.

Okay. And then -- thanks. And one last question, with what are pretty high oil prices still, do you or your partners, specifically, CIC, plan to maybe speed up the pace of development in the field?

I'll let -- Dave's in the room, our Managing Partner. He'll talk about that.

Yes, Gordon, what we're doing is we're doing the appraisal stage right now. I mean, what we want do is do the strata wells, get the information in front of us and do it right.

We're looking at maximizing the recovery of this pool, while maximizing the value out of the pool. So this year, coming up in the next 12 months, it's more stratigraphic testing, continue on with the pilot that we're doing right now. And actually moving forward, we recommend that we move forward with a second pilot in one of our large areas as well.

So that's the pace. And I think where you're going to see, as we said in the past, you start to see the production from all this appraisal work starting to come on in 2014, '15 time frame.

All right. Thanks.

Thank you. The next question is from Jason Frew with Credit Suisse. Please go ahead.

Hi, Murray. It's Jason. Hi, everyone, I guess. But hi, Murray, it's Jason with Credit Suisse. And I just thought I'd ask a little bit on the cost side, what you're seeing out there on the drilling and just what the composition of any kind of cost pressures might be in the business?

Well, kind of hitting on the overall cost pressures, we didn't actually see that much cost pressure in the first quarter in particular. What we did see creeping into the industry is some inefficiency. Basically, as the rig fleets got larger and you ended up with some less experienced crews, some inefficiencies start to creep in in drill operations.

One of the key things we'll be doing to offset that, going ahead, is culling our rig fleet from sort of 35 at the end of the winter, down to between 15 to 20 of our most efficient vessels suited for purpose rigs, as we march forward.

We can anticipate that the industry will have some upward pressure if crude oil stays high. But we haven't seen that much of it today.

Okay. Thanks.

Thank you. The next question is from Roger Serin with TD Securities. Please go ahead.

Good morning, everyone. I have a couple of follow-up questions, maybe, on the Q1 you drilled 153 net wells. Can you give me a sense of how many of those were tied in in the first quarter and how many others may be from previous quarters, that were drilled?

Nobody's going to do that. Nobody's going to take a rip at that.

Okay.

Natalie has her calculator going.

63 tied in.

63 tied in.

63 tie ins. Okay. And what sort of --?

Previous -- from previous quarters.

Yes.

In total we tied in 132 wells.

Okay. Perfect. And you talked about planned turnarounds. Can you give me a sense of what sort of production you expected to be impacted, at all, when, as budgeted?

Yes, we -- it's Mark Fitzgerald. We have major turnarounds, certainly, in Q2. Bill talked to the Crimson Lake facility that's down. We have our [Mitsu] facility down. And we have three non-operating -- very large non-operated facilities that have scheduled turnarounds in the second quarter.

Spectra is scheduled to be down in northeast BC, [Cara] is down in the west half of the Rocky area and then, of course, we have Atco down in Edmonton.

Bill also highlighted, we're really aggressive in this quarter, in terms of a lot of our maintenance preparation for future volumes and drilling programs, cleaning up facilities and otherwise in anticipation of the continued activity. So overall, those are significant turnarounds in Q2 and will impact us through the quarter.

Do you have a sense of BOEs per day, if they all went as budgeted?

Overall impact on the quarter?

Yes.

We're probably -- now each of those major ones are about 14 days. Each of those are on the order of 4,500 to 5,000 BOE a day, each, for that time period.

Okay. Perfect.

So about 4,000 barrels a day are recorded. But we had that in our budget.

Yes.

Okay.

So we offset that with carry-over tie ins from the first quarter, ongoing work in the second quarter. So, we're not straying from our guidance.

Okay. And one last question. You talked about, maybe for Hilary, some asset management. You've obviously done some -- it looks like you've done some dispositions and maybe acquisitions. Could you give us some color, do they net about equal? Or are you -- have you sold a little bit more, bought a little bit more, than one versus the other?

In general, what we're trying to do is remain production neutral. Obviously the timing, you can't always get things disclosed at exactly the same time, but I think you'll see over the passage of the year, that in general we'll be production neutral.

And there is always barrels that are going to be moving out, barrels that are going to be moving in as we continue to consolidate.

But nothing that would materially change either our forecasts or your budgets?

That's correct.

Okay. Thanks very much. I appreciate it.

Thank you. The next question is from Michael Zuk with Stifel Nicolaus. Please go ahead.

Yes, good morning, guys. Just a quick question in terms of capital spending. It looks like about one-third of your capital budget was spent in the first quarter. Just curious about how the rest of the year plays out in terms of capitalization? And I guess any read through in terms of meeting the upper end or lower end of production guidance?

On that -- on the capital side of that equation, Michael, the -- it's Murray Nunns here. The spending is about equally spaced between now and the end of the year. We're not -- we don't have it too lumpy right now.

There's only a limited amount of access, sometimes, in Q2 that you can achieve. So it's maybe the lighter of the three quarters remaining. But the others are about equally spaced. It's important to be, now, steadying out our rig fleet, in terms of overall costs.

In terms of guidance, as we said, we still believe we're within the range. The first quarter may have cost us 1,000 on our average somewhere, but we think we have the capacity internally to make that up over the year, and we're going to be working like hell to do exactly that.

Okay. Perfect. And just as an aside, can you guys provide any color in terms of the Rainbow pipeline outage and production that is associated with that.

Yes, the -- it's Mark again. On the Rainbow outage, as you're likely aware, its impacted transportation of oil pretty much everywhere north of that, which for us is Mitsu, Swan Hill, Red Earth. Our marketing group has been very aggressive with our field staff and very active in trucking those volumes to other receipt points and into other take away areas.

So as it stands, we haven't seen a major impact, in terms of our producing ability. And I anticipate we'll continue to be able to move those volumes to other receipt points in the future, here.

Okay. Thanks guys.

Thank you. (Operator Instructions). The next question is from Jonathan Fleming with Cormark Securities. Please go ahead.

Hi, guys. Murray, in your comments, you talked to identifying some key variables, with respect to drilling horizontal wells. I wondered if you could give us a little bit more color specifically on what those are?

A lot of it, Jonathan, is technique related. A lot of it is just the precision with which we put the pressure on the bit, how and when we do. That's one. Obviously the pad drilling is the second one, just exactly how do you organize your operations to be the most optimally efficient on the pad itself?

Fracture technologies, there's still refinement. And I think, and this is an important point to make about all our plays. Comparing early rates or wells from sort of mid-2010 and late 2010 to the results in Q1 2011 are of limited value.

Because as we've added fracs to the overall picture, what we've got is greater efficiency and higher deliverability on the first three months, in particular. So that's the other area where there's been a lot of refinements, is -- I think we've probably upped the average number of fracs. I'd say last year we were typically doing 10 to 14. And now we're in the 18 to 20 range.

So those would be some of the key factors, Jonathan, in terms of some of the efficiencies that are being driven.

Okay. And just a follow-up to that then. It's difficult for us to tell, when we just see the rates from these wells, but would you say that generally speaking your completion technique is improving over time.

it's difficult for me to tell, just looking at a group of wells, whether you're in a better part of the geology, where you're drilling? Or if you're actually getting better at the fracs and the completions. Can you comment on that a little bit?

Both. Both would be the short answer. I think we know how to identify the areas better. But all the areas are economic. But in terms of the efficiency of our fracs, the nature and the character of the way we put them away, the number we put away, the speed with which we put them away, all of that has improved our operational outcomes.

And I think it's important to note that what Murray and the team have been doing is technically true, the last three quarters of 2010, and even in the first quarter of 2011, on a lot of appraisal work.

So rather than, for example, in the Cardium, focusing on one or two areas, we focused on broad areas. We focus on a broad area in the Spearfish. The same on the Viking. The same in the carbonate.

What we'll see is that we'll start to narrow our focus a little bit. We'll start to lock in the better completion techniques. We'll start to lock in the better areas and as Murray said, you'll see, in the near term, and starting with some of the results that we had in the first quarter, we're going to get a better productivity on a per well basis in most of the areas and we're going to -- we're working very hard on cost efficiencies.

Very good. Thanks, guys.

Thank you.

The next question is from Jeremy Kaliel with CIBC. Please go ahead.

Good morning, gentlemen. A couple of quick questions for you. And apologies if you've answered this first one already. I -- your current production level, would you be able to provide that? And second, do you have any areas that are less exposed to spring breakup, that you may be able to get active sooner than others?

We're producing at 172 right now.

Sorry, I missed that.

172.

172 is -- that's not just capacity, that's what you're actually doing?

Right.

Great. And as far as areas that are less exposed to spring breakup? Do you have anywhere where you might get active sooner?

Yes, it's Bob here. I think, as Bill mentioned, probably the Viking in eastern Alberta and western Saskatchewan and Dodsland is in the area that's going to dry up quickest for us. And we expect to be back there right away.

And we are doing the pad drilling in both Swan Hills country and Cardium. That's really a limited extent this year, but I think when you see our programming expanding going into the next year, we don't think breakup will be as big an issue there next year. It will be a greater degree of pad drilling through breakup in the next year. But I'd say this year, the area that will get back the quickest is the Dodsland, Alberta.

Great. Thank you.

Thank you. The next question is from Kyle Preston with Canaccord Genuity. Please go ahead.

Yes. Thanks. Can you guys hear me okay there?

Very well.

Yes.

Yes. So just a quick question on, I noticed in your press release, you now talk about over 10,000 locations identified, which I notice is up from, I think, 8,000 that you had at your investor day a few months ago. Could you give us an indication on where you're seeing this inventory grow? And if possible, an approximate breakdown by the four key resource play areas?

I'll tell you the real reason why it's at 10,000. Other than the fact that we have a lot of land and a lot of locations, it's that, and I can say this as an engineer, sometimes engineers get very complicated with mathematics, but they can't add. So the 8,000 number, if you go back to our presentation, if you add the individual numbers, it was over 9,000 at that point.

So -- and we've pushed about another 1,000 into the mix with the work that's being done, results from the fourth quarter and what we're seeing in the first quarter. That's where we get over 10,000. So the eight was -- eight was a little understated because of the addition and we've added about 1,000 to it.

All right. Thanks.

Thank you.

Thank you. The next question is from Robert Bellinski with Morningstar. Please go ahead.

Good morning, everybody.

Good morning.

I was just wondering, as you realized the benefit from the current higher oil price environment, what's the impact on your time line for utilizing your tax pools? And when do you think you might begin starting to pay cash taxes?

Hi, it's Todd Takeyasu. The last one that we did was about at $100 and at that time we saw no change in the year in which we should start to pay cash tax.

It remains out there in the 2014, 2014 realm and still comes on in that 8% to 11% of cash flow range and based on our -- also our projected capital for out that far, it starts to steady state itself at about a 10% of cash flow number after -- at today's future strip. So it's -- it hasn't really changed much.

Okay. And then just a follow-up to the last person, what's the horizon for drilling those 10,000 wells?

We're presently -- we have to get a little bit busier than we are right now. We're currently doing it at about a 20-year pace. So that's one of the things that is challenging Hilary right now and Murray, is to pick up the pace, because of the number of locations we have.

What we can do in the short term is we do intend to focus our drilling a little more than we have over the last three quarters. And it could very well be that the busiest person at the table could very well be Hilary.

We may not be able to provide the capital to do it all ourselves and we may look for some creativity. But right now, to drill them all, it's about a 20-year horizon.

Okay. Good to know. Thanks.

Thank you. The next question is from James Odell with Point Financial Services. Please go ahead.

Thank you so much. I was wondering, you reduced your debt considerably over the past few quarters. Are you now down to a point where you're happy with the debt levels? Are you going to continue to try to reduce them further?

I think as I've -- when we go down and do our one-on-one's with investors and also do presentations that are on the web, we do talk about our balance sheet and we talk about the struggle that particularly Todd has had and the strong, strong work that Hilary did with some very creative deals to get our balance sheet into a much more pristine state than it was, certainly, in the -- at the end of 2008 and early 2009.

On an ideal point of view, we'd like to have our debt down probably a little bit more, maybe $100 million or $200 million. And as we look out and take a broader view of the last [gate], we believe that the fact that we're waiting to light oil, that we've got strong cash flow, means that we can internally capitalize our drilling program.

We don't have to go to the bank to get more money. In fact, we should have an opportunity to put a little bit against our debt this year and next. And as I look at others in the space, who may not have the blend of portfolio that we have, and are not achieving the type of cash flow per barrel that we're getting, even though they may have a little bit more pristine balance sheets right now, I wonder what the balance sheet in some companies is going to look like at the end of the year.

Okay. Thank you so much.

Thank you. The last question is from Kam Sandhar with Peters and Company. Please go ahead.

Hi. I have a couple of questions. First of all, just wondering if you could give us an update of what your well costs are in Slave Point and then more specifically what the well costs on the multi-lake lateral was that you drilled?

And then the second part of the question would be just on Seal, in terms of what you're looking for in terms of results from your pilot on SOR costs and any of the things that you're looking at when you're evaluating results there?

I'll let Bob Shepherd take a run at the first one. He's got the numbers.

Yes. So for -- Kam, for the first quarter here, the costs we saw in those plays for single wells was between just over $4 million. We still want to drive that down to the 3.5 range quickly.

We think that the incremental costs of doing a multi-lake well is going to be $1.5 million, so we should get those -- if we -- $1.5 million to $1.8 million. So those wells are going to cost us in the 5.5 to high -- in that range. But -- and again, we're seeing virtually an incremental doubling in productivity from the dual-lake wells. So we think there's great cost efficiency in that. And Dave will help you out with Seal.

Hey, Kam. I'm going to say, one of the things that we're doing on this project is gathering more data than looking at steam oil ratios.

For example, we're looking at injectivity. We want to see how much steam we can put into this well, in the configuration that we have. We also have it configured with our cross-well seismic. So we want to see the steam rises in the formation.

So right now, we're gathering information, so we can design the next phase of this project, rather than just focus on steam oil ratios and rate.

If we were to take a look at comparables out there, we should see the steam oil ratios in that 1 to 2 range and we should probably see some rates that get up to peak about that 400 to 500.

At the end of the day, what we're doing is we're building this for the long term. We want to see how things rise, how the seismic works and all the different monitoring techniques. We think that's a long term plan. Thanks for the question. I appreciate it.

Just one more, quickly. Where do you guys reference that you're looking potentially at doing the second pilot at Seal? Where would that be planned to be started?

Yes, that's in the Harmon Valley South area. That's where we've done some horizontal wells in that direction. And we'll probably get into that one with some application sometime this year and next year, we'd be looking at pilots in that area.

Kam, that's the area that you're very familiar with the [Connaughton] area, where Shell and [Baytex] are and Harmon Valley would be almost immediately south of that, separated by about 10 or 12 miles away from Connaughton.

Yes, I think -- yes, it's probably about 15 miles from Connaughton.

Yes.

A couple of townships over.

Thank you.

Okay. Well, I think that's about it. Thank you all very much. We -- most of you on the line, if you have further questions, don't hesitate to email us. Jason is always available and Murray and Hilary, Todd and myself will endeavor to make ourselves available through the day if you have any questions.

Those of you that are listening, that are retail investors, we welcome your questions at any time and have had a good discourse with you in the past. And we hope to continue that in the future. So thank you very much. And good morning.

Thank you. The conference has ended. Please disconnect your lines at this time and we thank you for your participation.