Obsidian Energy Ltd (OBE) 2012 Q1 法說會逐字稿

Good afternoon. My name is Matthew and I will be your Conference Operator today. At this time I would like to welcome everyone to the Penn West Exploration first-quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions) Thank you. Jason Fleury, you may begin your conference.

Thanks, Matthew. Thank you and good morning. Welcome to Penn West's 2012 first-quarter financial operating results conference call. My name is Jason Fleury. I'm responsible for the investor relations group here at Penn West. With me this morning in Calgary is our President and Chief Executive Officer, Murray Nunns; Chief Operating Officer, Hilary Foulkes; and Chief Financial Officer, Todd Takeyasu. And other members of our senior management team.

Before we get started this morning, I would like to quickly remind listeners to our customary conference call advisory. Penn West Exploration shares are traded both in the New York Stock Exchange under the symbol PWE, on 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 on a 6 to 1 conversion ratio. All financial data are reported under International Financial Reporting Standards, or IFRS. Certain information regarding Penn West and the transactions and results discussed during this conference call, including management's 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. And are also asked to review the advisory notice therein. The news release can be found at www.pennwest.com. Participants are also cautioned that the included list of risk factors contained within that release is not exhaustive. Official information detailing other risk factors that could affect Penn West operations or financial results are included in the reports on file with Canadian and US securities regulatory authorities. And may be accessed through the SEDAR website at www.sedar.com and the SEC website at www.sec.gov, or at our own website, www.pennwest.com.

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

I'll now turn the call over to Murray Nunns, President and Chief Executive Officer. Murray?

Thank you, Jason. Before we get into the formal part, I just want to remind shareholders that Penn West Board of Directors has declared a second-quarter dividend of CAD0.27 per share to be paid on July 13, 2012 to shareholders of record on June 29, 2012.

With the largest asset base for light oil development in the petroleum industry in Canada, our aim over the last two years at Penn West has been to derisk these light oil opportunities. And build up large-scale execution skills to support our growth and yield model. All of our major tight oil plays are in full development mode. And through appraisal drilling we continue to add to our already deep project inventory. Over the last 24 months, we have proven the application of horizontal multi-frac technology to a wide variety of different settings. We have tested and tweaked the technology to maximize deliverability from our wellbores to the point our type curves meet or exceed industry averages on every trend where we operate. We have captured additional resources providing us with long-term growth trajectories for all of our plays. And, most importantly, we have the confidence and willingness to capitalize on the predictability and repeatability of our drilling inventory to deliver results for shareholders.

In conversations with many of you on the call this morning, it's clear that the progression of Penn West has been obscured by the events of 2011 and ongoing dispositions. It's about time we cleared some of that fog away. Right now, Penn West is producing 35,000 BOE per day of high netback crude from horizontal multi-frac wellbores. This constitutes 20% of our current production base, and is growing. Each of our major plays is currently delivering between 6,000 to 10,000 barrels per day of production from horizontal wells. Q1 production was 167,400 BOE per day, which is in line with expectations. A notable positive step after selling approximately 4,500 BOE per day in the first few weeks of January.

Later on, on this morning's call, our COO, Hilary Foulkes, will walk us through the operational highlights of the quarter, including a drilling program overview and execution and play updates. After that, our hard-working and seldom-sleeping CFO, Todd Takeyasu, will then walk us through some of the financial pieces of our business which makes all the operational momentum possible. After that we will take questions.

But just before that, let's take a step back and look at the broader issues impacting Penn West and the industry in Canada. Underpinning our oil-focused strategy has been the steady growth in oil price, driven by continuing strong global supply-demand fundamentals. At the same time, Penn West and the industry have experienced some significant challenges in the last 24 months. And let's just enumerate them real quickly, just for sport. Forest fires, significant flooding, CAD75 oil, a euro debt crisis, sub CAD2 natural gas, and now CAD30 differentials on oil for a short time during the quarter.

During this time, we have made a variety of strategic moves to continue operational momentum. I'm certain everyone on this call has been watching the market volatility, and watching it again this morning. Driven by lower natural gas pricing and the temporary widening of crude oil differentials in Q1. Just as dramatic has been the narrowing of differentials in the first month of the second quarter. Western Canadian light sweet crude went from differential highs of CAD30 on a daily basis in March to June forward contracts at about the CAD2 mark.

In the first quarter of 2012 a significant number of both planned and unplanned plant outages, limitations of existing infrastructure, and rising supply, combined to produce wide oil differentials between Edmonton and West Texas crude pricing. As US refineries came back online, crude differentials had narrowed to more moderate levels. Short-term, the issue appears to be resolved. We remain confident in the ability of North American infrastructure capacity development to accommodate Canadian oil producers' access to market.

Current US pipeline and infrastructure and near-term expansion projects already underway will deliver growing North American crude oil supplies to key refinery sites. Canadian and US crude sources can displace imports and compete on a global basis, provided the pipeline development is done on a timely manner. In the near term, though, important projects involve the pipeline projects from Cushing to the Gulf Coast, allowing additional crude oil to flow to the Texas and Louisiana refineries. Which has the largest concentration of refining capacity in North America.

Canadian pipeline expansion is crucial to support access to Atlantic refiners through either the repurposing of East Coast pipelines and to Asian markets through the expansion or development of pipelines to the West Coast. Long term, our strategy and goal at Penn West is relatively straightforward. It is to have 50% of our crude oil accessing saltwater ports for refining or transport.

Turning back to the asset base, Penn West has been externally focused on proving and aggressively expanding our deep inventory of opportunities. And developing our large-scale execution skills, as we noted previously. This combination sets up the growth engine for Penn West. With that, I'll turn the call over to our Chief Operating Officer, Hilary Foulkes, the key driver of that growth engine. Hilary?

Think you, Mike. As Murray said, the success of this Company is driven by a combination of execution and inventory. And I'm going to update you on just that. Penn West made drilling news last week in Canada. The headline from the Daily Oil Bulletin here in Calgary read -- Penn West drilled the most meters in three months ended March 31, 2012. It's certainly nice to have this third-party validation. However, the real story behind the headline is that we can plan, procure, and execute on a large scale. It means that we are truly in the development phase of our light oil plays.

In Q1 we set execution records for the Company. We laid over 1 million meters of pipe, we placed over 2,800 fracs, and rig released 179 wells. We've also accumulated a great deal of experience on these trends, more than any company in Western Canada. We now plan our activity based on a deep inventory that is yielding predictable results.

Heading into the specifics of our Q1 activity, I'd like to provide an update on our four key tight oil plays. In the Carbonates of northern Alberta, in just two years we've grown this play from pretty much zero to its current production of over 7,500 BOE per day from horizontal wells. We believe there is tremendous opportunity in this entire region. I'll give you a quick update on Swan Hills before we dig into the play points. We are continuing to selectively develop the most prospective portions of our land. Our results are encouraging and in Q1 we were active in both East Swan Hills and Virginia Hill. As we face no exploratory issues, we continue to let the industry derisk the play for us.

At Slave Point, we have a case study of a successful maiden Penn West play. It is a clear illustration how we, as an exploration and production company, can take a play from concept to development. Let's take a look at the three major areas of this trend. At Otter, we are in full-scale development with years of growth ahead of us. In Q1 we had four rigs active, drilling predominantly dual laterals with initial rates in excess of 300 BOE per day. At Red Earth, the appraisal work is largely concluded, and we're transitioning into development phase. At Sawn Lake, there is more appraisal work to be done. However, the results are very encouraging. We drilled six single-leg appraisal wells that we'll bring onstream late Q2, early Q3. Indications are all very positive. Our confidence in the area is high, as our two discovery wells are producing a combined rate of over 500 BOE per day after 12 months.

Facility capacity and control is crucial in this area. And we are expanding facilities to ensure our appraisal and development work does not slow down. Gas conservation is a critical path item and our expanded plant will be ready late summer. This gives us further running room and a distinct competitive advantage. We now own more than 400,000 acres of land. And the ultimate potential of this play continues to impress and expand. We believe we already have the conveyor belt set up for more than five years of growth. Going forward, we will continue to develop this play aggressively. We had seven rigs working during the first quarter, and we expect this pace to continue after breakup.

The Cardium is the largest light oil play in Western Canada, and we are the anchor tenant, with 665,000 acres. We have the largest position by a factor of three. Since 2009, the industry have drilled over 1,400 horizontal wells and has added approximately 50,000 barrels per day of production on this trend. We're still in the early innings of this play redevelopment. For Penn West, the Cardium has the greatest potential of any play in our portfolio. Through both primary development drilling and the private enhanced oil recovery, we are in this for the long run. We deployed six rigs over the first quarter, drilled 28 wells, and tied in 36 wells, including our eight wells at Willesden Green. We're using water-based fracs in approximately 75% of our completions. Not all areas of the Cardium are created equal. And we like the areas we have. Our type curves at West Pembina, Alder Flat, and Willesden Green continue to exceed industry averages. Penn West horizontal volume on the play now is almost 10,000 barrels a day.

In the Viking, we continue to benefit from the excellent economics of this play. The Dodsland portion of the play is in full development with no surprises. We see multiple years of development in Saskatchewan. In eastern Alberta, we have in excess of 0.5 million acres of Viking rights. To date, we've drilled 20 appraisal wells and identified a potentially significant oil resource. Our three most recent wells have come onstream at a combined rate of approximately 600 barrels a day.

In Manitoba, the Spearfish play is in full development mode. We have five rigs running in Q1 and drilled 37 wells with very predictable results. We are currently producing over 8,500 barrels a day from horizontal wells. We expanded our facility to 13,500 barrels per day. And we anticipate filling that facility by late this year or early next.

Now, an update on spring breakup. The weather in Western Canada has been relatively normal. And spring breakup has not been the aberration we experienced last year. However, regardless of what Mother Nature threw at us, we were ready. The wells we wanted to tie in during the first quarter were drilled by January 31, and tied in by March 31. We laid pipe to lease edge, and we had gas and tanks in place by mid-February. We spent capital on roads and infrastructure to ensure the long-term growth potential of our plays.

Our program now in Q2 calls for relatively limited activity, As anticipated in our guidance, during Q2 we are not doing a lot of drilling and we're not doing a lot of tie-ins. Key activities that will occur in the quarter are maintenance and turnaround at both Penn West and third-party operated facilities. We expect peak volumes off line will be in the 8,000 to 10,000 BOE per day range for portions of the quarter. The predictability of the plays, the results, the depth of our inventory, and our execution capabilities give us confidence in our annual average production guidance. It remains unchanged at 168,500 to 172,500 BOE per day.

Of course the ability to capitalize on our oil potential is facilitated by capital and financial discipline. And so with that, I will turn the call over to our Chief Financial Officer, Todd Takeyasu, and he will take you through some of those related strategies.

Thank you, Hilary. One of the keys to executing our long-term growth strategy is maintaining financial flexibility. At Penn West, financial flexibility and capital discipline are centered on balancing the following concepts. First, maintaining an appropriate debt capital structure. Second, an active hedging program. Third, funding our exploration and development capital while maintaining our balance sheet ratios. And fourth, paying a consistent dividend.

We believe our current capital structure is appropriate. Over the past several years, we have increased the term of our debt capital by issuing senior unsecured notes, mostly in the US private market. We have been consistently rated NAIC2, which provides us mid-investment grade pricing. Our known portfolio is now in excess of CAD1.9 billion, with an average of 6.3 years of term at quarter end. Our portfolio is nicely spread out over those years.

We also have approximately CAD1.3 billion of undrawn capacity on our CAD2.75 billion bank syndicate, which has approximately 3.25 years remaining. We believe our current senior debt to EBITDA ratio of 2 is in line, given the current low natural gas pricing environment. We are mitigating against future volatility in Canadian crude oil differentials, using direct marketing and hedging. The Commodities and Transportation Department is moving towards direct sales of oil to end users to reduce our future exposure to the aforementioned oil differentials. To date, we have committed 35,000 barrels of oil per day on the Enbridge Wrangler project to enable us to market our oil to the US Gulf coast. The first phase of 150,000 barrels per day of this project is expected to be onstream in less than a month -- May 17, that is. With an additional 250,000 barrels per day next year.

We are carefully monitoring other pipeline developments, many of which you've probably heard of in the news, with the goal of getting our barrels access to international pricing or to reduce our exposure to bottlenecks at Cushing. Also to guard against wider Canadian oil differentials in the near term, we've been moving up the floors on our West Texas intermediate based oil collars. For 2013, we currently have 41,000 barrels of oil per day hedged, with an average floor price of CAD94.51, which about a CAD9 per barrel increase over our 2012 hedge floors of CAD85.53. Overall, our aim is to provide the Company with funds flow certainty to fund our growth and dividend.

We are uniquely positioned to develop high netback light oil production after we adopted this strategy several years back. As Hilary just discussed, we have many years of low-risk development work in our four larger oil plays remaining, combined with very promising enhanced oil recovery projects. And of course our joint ventures with world-class partners. To supplement our pace of development, we consider non-core asset divestitures as another source of capital in addition to our funds flow. We have a portfolio of many other properties of various sizes, which are prospective for horizontal oil or liquids-rich gas development. These assets are currently under the market radar for the most part.

A portion of these plays are not suitable for large-scale development in a Company of our size. Our A&D group continues to be able to package properties suitable for the market, as evidenced by dispositions in the current quarter of 4,500 barrels per day of non-core production for proceeds of CAD322 million. The leading oil and gas weighting on those barrels was about 80% oil. Our capital guidance for 2012 remains at CAD1.3 billion to CAD1.4 billion, net of acquisitions and dispositions. We view our oil-weighted portfolio of non-core producing assets to be a source of our financial flexibility. We continue to see many gas-weighted companies and other non-traditional domestic and international players seeking physical oil exposure.

We believe our dividend demands we make prudent capital allocation decisions. And it prevents us from over capitalizing our plays. Many investors continue to tell us that our dividend provides them with a certainty of return in these volatile capital markets, and today being no exception. Looking forward, we can vary the pace of our development programs and continue to realize at value from our non-core assets, as we require. Longer-term, we seek to maintain our dividend at the current level of CAD0.27 per quarter. And we haven't changed one bit on that.

Just before we take some questions, I'd like to introduce the other members of our senior management team in attendance today. In addition to Murray Nunns, Hilary Foulkes, and Jason Fleury, with us today are Mark Fitzgerald, Senior VP of Development; Gregg Gegunde, Senior VP of Production; Thane Jensen, Senior VP Operations; Keith Luft, General Counsel and Senior VP Stakeholder relations; Bob Shepherd, Senior VP Enhanced Oil Recovery and Cordova; Rob Wollmann, Senior VP Exploration; Jeff Curran, VP Accounting and reporting; David Stern, VP Commodities and Transportation.

I would now like to turn the call over to the Operator and open up the phone lines for questions.

(Operator Instructions) Greg Pardy, RBC Capital Markets.

Three questions for you. One is, just curious if there is potential for further asset sales in the second half of the year. Secondly, I am wondering if you can dig into just the risk management loss of CAD19 million of debt,. And just lastly, just wondering if there is any change in how you're going to allocate capital amongst plays and so forth, just given the commodity price landscape we're in. Thanks very much.

Super. Thanks for the question, Greg I'll start off maybe on the asset sales. Because I think this really gets to the heart of the stage Penn West is at. Over the last two years, we have continuously sold off non-core assets to fund the program and develop the ability to grow these assets on a larger scale. We believe we are at a bit of a pivot point, that we have that ability. So we will look towards select further asset sales of, I'll call them, more ones that really just aren't a fit with the portfolio.

Beyond that, we'll also look at the joint venture market. We believe that we could infuse a significant greater amount of capital into these assets and pick up the pace further in the future. We have to, obviously, wait until the commodity market will also allow us to, at certain times, we may need to see a little recovery on some of that side, and have some certainty there. But in a general sense, our aim will be to accelerate the pace of capital flow through these assets.

So that's on that side. I'll have Todd just touch on the risk management piece. And then maybe Hilary can pick up on the forward focus or shifts in the capital program.

Sure. We have a CAD85 and CAD53 floors on our West Texas floor calendar 2012. Of course, we've seen spot West Texas run in excess of that, which for the most part triggered the loss, which you see. The reason that we've floored our collars at CAD85.53 was, our business plan for the year was really premised on an CAD85 West Texas, which we would have laid out at Investor Day. And the only other color I would add there is that we do have a bit of an offset on that number because we did hedge out the foreign exchange at 1.02 related to those collars. So it looked bad, but at the time that we were flooring at our CAD85, we weren't real certain what was going to happen with Europe, and we wanted to protect our capital program.

Okay. So those are strictly on crude, just so I understand. And are these monthly settlement?

Yes, they settle monthly. And the CAD19 million is really net of our oil and our gas.

Okay. Thanks for that.

And, Greg, maybe I'll just finish up here with the question on capital and whether it's going to be reallocated on a go-forward basis, or if there are any tweaks in the program. I'd say that the biggest transition for us has been from Q1 2011 into Q1 2012. And that's where we did start to shift a lot of our capital programs into essentially the western part of the basin, where we have deeper targets, higher EURs and volumes, of course, commensurate with that. So, that transition really took place over the course of 2011. So our Q4 program last year and then into Q1 of this year, focusing very much, obviously, on the Cardium and the Carbonates.

That will not change on a go-forward basis. So we'll continue to add capital into the shallower plays in Viking and West Gate. Those are great economics. We love those plays. But the shifts that we made, really, over the last year is not going to change. We're going to continue our focus there and pick up the pace.

Okay, thanks for that. And just one follow-up, then. On the potential asset sales you might move forward with, are we talking CAD5,000 to CAD10,000? Or is it just too early to say what the order of magnitude might be?

I think, Greg, at this point, we want to see the commodity market and the differential market unfold a little bit more before we make our calls on which direction we're going to go.

Okay. All right. Thank you.

Brian Kristjansen with Canaccord the newly.

I had a question about the Slave Point. I noticed you got some really solid wells on the Red Earth side of the play. And wanted to know what your plans are for development on that side and for infrastructure.

We'll put this question to Robb Wollmann, our Senior VP of Exploration.

Thanks, Brian. Yes, we've had some good early results in Red Earth. We do have a deep inventory there. We're going to layer in more activity in the second half at Red Earth. That being said, if you look at the slave Point overall, our results at Sawn have continued to be excellent. And our system results in the development phase at Otter are giving us a lot of confidence to keep that program going. Just to reiterate what Hilary said, our expectation of accelerated capital in the Slave Point is being underpinned by those well results.

Could you break that out maybe by percent of Slave Point going to Red Earth, Otter and Sawn?

The bulk of it is still going to be in Otter because Otter, we've got the infrastructure ready to roll. We just continue to drill dual laterals in that area. So, very consistent competent rock. So, it's still the bulk of the Slave Point capital is going to be going into Otter. As then, as we mentioned, a little bit more appraisal work at Sawn. And then we will start to shift a little bit more of the balance into Red Earth. But I think Otter is still going to command the greatest capital going forward, at least in the short term.

60% to 70% probably in Otter, 20% in Sawn, and 10% to 20% in Red Earth.

Thanks. Any facility construction on the east side there?

We are currently expanding both the battery at Otter and the gas handling facility at Red Earth, which really services both the Otter and Red Earth areas. So those expansions are currently underway.

Okay. With respect to waterflood on the Otter side, I saw your recent application. Do you know what your plans are for 2013 in terms of waterflooding at Slave Point?

I'll turn this question to Bob Shepherd, our Vice President of EOR. I know it's in the early innings for the thinking. In fact, Bob probably hasn't even gotten all the projects to the table with us yet. So if Bob goes too far, I'll put a gag order on him here. So, anyway, fire it up, Bob.

We like the potential of Otter for waterflood. We will be starting our first project out there. We'd like to have water going in the ground, ideally by the end of the year. It could be early in the first quarter. But it really is just going to be the beginning of continuous buildout of that waterflood. And we want to keep that program really within one to two years of the development program just so we optimize ultimate recovery.

So would you be rolling out or expanding that existing application through 2013?

That will be the plan. It's something I have to go through with the team here. But that's the current perspective, is yes. The whole thing at Otter, most of that play looks to be amenable to waterflood. And so our plan is just to not get too far behind the development program. We've got a couple of years to go, we don't have to be right in behind it, but we like Otter.

And I will just tail in on that, Brian. And a broader commentary on EOR in general within the Company. We see this as a very significant piece of our business going forward. The marriage of horizontal technology and the EOR technology. We believe that Cardium and the Carbonates are going to be key centers for us. Beyond that, we also have about 150 other waterflood projects and EOR projects across Western Canada. And we're going to be looking at virtually all of them because we believe it presents a massive long-term opportunity for us.

Great, thank you very much.

Jonathan Fleming, Cormark Securities.

I also have a couple more questions on your Slave Point play. I'm wondering, generally speaking, how is the play shaping up relative to expectations? And can you comment at all on the consistency of the well results on the play?

I'll turn this one to Hilary. I think, Jonathan, she's the perfect person to answer that question.

I'll just tell you that we are absolutely in love with this play. It's meeting expectations. I think that's conservative. We're excited about the predictability of it. The ability for us to go into the Otter areas and do those dual laterals is a huge advantage. And we're going to continue to put a lot of money and time and effort into this. I'm not sure if that answers all your question. We get a little carried away when we start talking about Slave Point.

I wonder if you can chat a little bit more about the completions. There are several players in there following slightly different completion methods. Clearly Penn West following the dual lateral development methodology. What do you see as the economic uplift related to duals relative to single leg wells? And then, secondly, is there any opportunity to improve the capital costs on the play go forward?

I think we'll flip that question, too. I'm looking for Mark Fitzgerald, our VP of Development, who's knee-deep in the Carbonate work.

Jonathan, our look-back and assessment is we firmly believe what were doing on the dual laterals is the right way to develop the Slave Point. As Bob talked to you, there might be a little bit of optimization and movement as we carry forward with the EOR component of that and make sure we are positioning this go-forward. But in terms of the economics of the play under the dual laterals, the ability to be very efficient on the execution side with that, and how that evolves long-term, in terms of ultimate recoveries and economics, certainly we're happy there. As it relates to the completions, I think we all, as we move forward, continue to tweak and test and will continue to do that as we move through the year to optimize completion costs and results. But as it stands right now, as Hilary said, we're quite happy with what we're seeing and where we're going there.

Good stuff. And then last question from me. From a strategic perspective, I think when you say you're in love with the play, I get the idea. But how does the Slave Point stack up relative to the rest of your portfolio? And can you comment at all on where you see capital spending going 2013 relative to 2012? Is there an opportunity to spend 50% more capital on the play next year? Is that a reasonable assumption, or should we be maybe more conservative than that in our thinking about how you guys develop the play?

Jonathan, I think Hilary and I will take this on and put it in the broad context. The 800-pound gorilla is still the Cardium in terms of just plain oil in place. But the Carbonates is now, two years in, double what we thought we had up there. We used to think we had a two- to three-year trajectory. We now believe we have a five- to seven-year-plus trajectory on it. So we need to at least maintain the current pace of capital, if not increase it by 10%, 20%, 30%. Ultimately, these deeper, larger, higher deliverability plays on a per well drilled basis are the direction we have to go as a Company, to impact on asset base of this size. So the Carbonates, don't think less, think more.

Good stuff. That's very helpful.

Katherine Minyard, JPMorgan.

Just a couple of quick questions. The 2012 investment program just overall is about 85% geared toward development, and it's mostly light oil. And last year you had about a 35% development focus in your CapEx program. So as we look at the well count in the first quarter, you've got about 151 net oil development wells, and you had 145 in the same quarter last year. So it's a little bit more of a modest increase just on an absolute well count basis.

So could you talk a little bit about some of the factors that differentiate the types of wells you're drilling in the first quarter of 2012 versus the first quarter of 2011? Either just the nature of the well drilled itself or maybe the concentration of the wells in the main four light oil plays?

Sure. It's a natural question for Hilary.

Sure. The real change, when we defined our development wells, there's still an appraisal component to those in 2011. So, when we looked at our overall capital allocation of about 35% of development in 2011, there was a huge appraisal component associated with that. So the 35%, although they statistically show up as development wells in the releases, we're still learning on those wells.

What we took from those learnings last year we applied to more concentrated development this year, and more concentrated from a geographic perspective. So just as an example, instead of drilling many areas of the Cardium in 2012, what we've done is focused on Wiillesden Green, Alder Flats, and West Pembina. So that's really the transition that we've made from 2011 to 2012, is being much more specific about the areas within a larger play area.

The same really goes for the Slave Point in that we focused in very dense drilling gas in the Otter areas this year, whereas last year we were trying wells in Red Earth. We were drilling a little bit in Otter. And so we were shifting our drilling program around in order to learn how to do it better. So that's the biggest change. I would say also we've moved, from a basin perspective, a lot of our capital towards the west. What that means is you're getting into deeper drilling, you're doing multi-well pads, we're doing dual laterals in some of these areas. So that's been a learning and a shift from 2011 into 2012. Did I catch everything you were asking?

That's great. Thanks. And then just another question. If I could just go back to some of the prepared remarks, as well as what was in the release. You've talked about the current Canadian differentials, and commenting on the wide differentials that you saw in 1Q that have started to narrow following refinery turnarounds. You could talk about the benchmark or the market observable narrowing the differential. But can you also give us some insight into what you might be seeing specifically, just given the fact that you guys are moving towards direct marketing of your own oil to refiners of choice? Is there anything different that you're seeing versus the benchmark? Or are you seeing pretty much similar results in term of differentials?

What we're generally finding is that the postings in the market are not reflective of what might be actually transacting over the balance of the year. So as we said, we see the June immediate to CAD2. You see a posted differential of about CAD8. And so there is a gap right now.

I think, obviously the refiners would love to hold onto a little more profit for a little longer. That business doesn't always make money, so when they get a chance to, they like to hold onto it. So that's the general trend we're seeing, is that it's driven lower quickly as the refinery capacity is available. And so we're generally seeing it, it's been narrowing faster on an immediate basis than the postings are showing.

Okay. That's good. Thanks very much.

Gordon Tait, BMO Capital Markets.

I have a couple questions just on your costs. It looks like maybe, just to break it down into two areas, could you maybe talk about what looks like some cost creep on your operating cost side? And then, secondly, on the capital costs, given that in Q1 you were the most active driller in Western Canada, is that going to translate into better pricing on services on drilling and completion services, and therefore that capital efficiency? So could you maybe address both of those?

Sure. I'll take on the first one here. On the ops cost side, I think there's two factors that are holding our ops costs a little persistently higher than we like to see it. Well, three really. The first being, we've seen higher electrical costs, which seems at odds with low gas prices, but that's the reality of capacity in the Alberta. So that's been one of the drivers.

And I'd say the second portion, and this is an important one, is now that we've got a set of 700 to 800 horizontal wells producing within the context of the Company, there's a pattern to repair maintenance with these that we're still learning about. And what we're finding is we're doing a bit more repair maintenance work a little earlier than you would in the lifecycle of vertical wells, just because you have the equivalent of 16 wellbores flowing up one wellbore. So those are the two primary drivers.

The third is we're undertaking a significant program of automation in our fields. A lot of our fields, the old verticals, are based on 1960's technology. We still have 1,000-plus operators that touch the iron everyday. And we're going through a process of automating that end of the business and absorbing some costs for that, as well. So those are the three contributors to our ops costs being a little bit more persistently high than we'd like to see it.

Then on the cost structure capital efficiency side, I'll give the question to Hilary.

Yes, so on the capital efficiency side, there's a couple of key elements that I think are worthy of note. The first one is, because we now know and have confidence in the predictability of these big oil resource plays, we're actually getting ahead on the facilities and infrastructure side. So there is significant investments that we're making, even in roads, so we can ensure greater access into these area, as well as on the facilities side. So there is that part of non-productive capital that we're spending in anticipation of five and six years growth in these plays. So that is one piece.

The other part is simply on the service costs. And we are always hopeful that day rates and the like are going to start to come down. And maybe with some of the tension from less gas drilling going on in the industry will help with that. We know that getting better iron, getting consistency in the rigs, parking a rig and having it drilling up in Otter for an entire -- well, for six or seven months at a time, we start to gain efficiencies there. We are gaining efficiencies, as we speak, on the completion side. We're learning how to do these better. So we should see some improvements just in terms of even the time it takes us to do things, even if it's not a material cost.

The labor side is always a struggle. The oil sands are doing well. We compete with oil sands and construction for labor. And we are not seeing that that is going to lighten up much in the near term. So what we've planned on a go-forward basis is really to hold our own. We're hopeful will see some reduction in those service costs. But from a budgeting perspective, we haven't anticipated that. And then we continue to put pressure on service companies to help us with those costs.

And really, just a bit on Hilary's last note, with cash flows in the industry down, with the banks putting pressure on a lot of people, we anticipate demand isn't going to be as high in the second half for some of the equipment. Heaven knows the service guys will try to hold onto their profit margin. But we will definitely keep the pressure on that side of the business. Because if there's ever a time to gain some of that back, it may be in the second half of this year.

Okay. And then just lastly, to get to the midpoint of your guidance range, it looks like you're going to have a pretty back-ended production profile. In other words, most of the growth is going to be in the second half. Because I wouldn't think we're going to see a lot in Q2 with spring breakup and plant turnarounds. Is that how you see it?

I'll turn that one to Hilary.

Yes, that's absolutely what we see. Because we're drilling these wells, imagine you're drilling a four-well pad, it's taking you 20 days to drill each of those wells. There's 80 days to drill a well. That's before you do any completions or facilities or tie-ins. So, it does take longer. So, what we have now is a little bit of a rabbit and the snake. And over the course of the second quarter, we're not anticipating a lot of activity, just from an access perspective. And then into the beginning of the third quarter, or as soon as weather permits essentially, we will start to see that production ramping up. And this was all part of our original plan and things are unfolding as they should.

Okay, thanks.

Jason Frew, Credit Suisse.

Just to follow on from Gord's questions on capital. I just wanted to ask more about the level of capital before asset sales. And I was looking at the number of CAD660 million in the first quarter. Which looks like about 40% of budgeted volumes. And my concern, and maybe you could help me with it, is that last year and the year before, Q3, Q4 capital was higher than the first. And at CAD660 million to start the year, I'm just wondering if there is upward pressure, or how you're looking at the back end of the year in terms of capital deployment.

Jason, the CAD660 million is as planned. I think one of the things that's built into that CAD660 million that isn't built into the volume, I think, as you said, links to the previous question, is that we're carrying a very large inventory forward out of the winter, of wells that are in varying stages of completion or ready for tie-in. And not only are we carrying that forward, it's also focused, and tends to focus, on the deeper wells. So that embedded in that CAD660 million, and embedded in that 40%, even though we're at that point, we really have only tied in less than one-third of our wells for the year. Probably between one-quarter and one-third of our wells for the year are tied in. And those tended to be more focused on the shallower variety.

So we believe there is ample ability within the dollars we had located within the capital budget to hit the targets as we bring on these larger deliverability wells into the third quarter. So we're comfortable with that part of the program. It just begs the broader question, again, if we do any asset rotation, one of the things we like to do on a continuous basis is to operate the machine at a higher level. We like to -- continuous operations is the easiest way to operate this organization. So that will be something, again, we'll look to later in Q3, Q4. But that would be with additional gains on volume, or offsetting what we're selling and upgrading our asset base.

Okay, thanks.

Katrina Karkkainen, FirstEnergy Capital.

Can you give us some further clarity on turnarounds in the second quarter? In particular, how much is third-party and where the largest turnarounds are located?

I'll turn it over to Hilary and she can go from there.

Good morning. Most of the turnarounds, the biggest turnarounds, I will just list them off, first of all, and then we will backtrack on them. So, Weyburn, we've got turnarounds at Otter, we've got turnarounds in Pembina and Dodsland. Those are the biggest ones. For the most part we are looking at third-party turnarounds here. So Weyburn, the Pembina turnaround and Dodsland are all third-party. The Otter turnaround is our own plant.

So, 8,000 to 10,000 barrels a day at its peak is what we're expecting. There's a lot of smaller turnarounds that are all tucked in there, as well. We've got some in Coalville. The second quarter is when we have both labor, equipment, and the ability to actually get this done while the road spans are preventing us from access elsewhere. As an industry, we just lump this in the second quarter and get all this work done.

Thanks very much.

Ronny Eisemann, Dahlman Rose.

You touched on both the questions I'm about to ask, but I will ask them in a different way. With the increased workovers and repairs in Q1, is that going to be an ongoing basis issue, especially now with the focus on horizontal drilling? And if it was more of a one-time issue, what was the impact on a per barrel basis? And then this quarter, or Q1, you drilled roughly 10% to 15% more wells than you did in the first quarter of last year. Does the same trend hold in terms of completions? Did you complete roughly 10% to 15% more wells in the first quarter than last year? Thank you.

Okay, thanks. Ronny, I'll touch on the ops cost question and then turn it to Hilary on the general completions question. I think in terms of the maintenance dollars associated with these horizontal wells, there seems to be a natural function that occurs about 12 months into the wells where you have to have certain casing gas compression, you have to have a variety of cleanouts done. It just seems that as you come off the production after about a year, that's the natural time.

So we see this as, there's an ongoing cost that will occur with every new well you drill about a year in to do that kind of work before it returns. It seems to right now be at about CAD1 to CAD1.25 a barrel. That cost may be about CAD1.50, is a rough estimate of the range of it. So it's one that we are very much watching on a going-forward basis as to seeing how it plays out over the longer run. But that's the general trend, is CAD1 to CAD1.50 is tied to these horizontal wells. And then it seems to occur about 12 months into their new life.

For the completion side of the equation and where we were last year, this year, I'll turn it back to Hilary.

Just to give you a little bit of a sense, over the first quarter, we actually tied in 142 wells, or brought onstream 142 wells. So percentage-wise, if you go quarter-to-quarter as a means of comparison, we actually brought onstream more wells percentage-wise than we had done in the past. But there were also wells that we were trying in in the first quarter that we started activity on in 2011. So it's not a dead start on January 1. There were wells that carried over from the fourth quarter of last year. But 142 wells brought onstream in the first quarter.

Just going back to the workover issue, do you expect that CAD1 to CAD1.50 to grow over time as a greater amount of your production and inventory come from horizontal wells?

Could you just repeat that question? I'm sorry.

Since your inventory of producing horizontal wells is growing, do you expect the workover costs, which are currently running between CAD1 to CAD1.50 per barrel, do you expect that to increase gradually over time as the horizontal well inventory grows?

No. Once they reach a steady state between 12 and 18 months, they tend to settle into a pattern. And I think we won't see that growing. I think it will just more become a steady state feature as we bring on new wells.

Great. Thank you.

Roger Serin, TD Securities.

Most of my questions have been answered. I just wanted to go through a couple of things. So if I was to look at your Q1 asset sales, and Todd talked about it being mostly oil, if you had had that production, because it sounded like it occurred early in the quarter, would your liquids production have been more in the range of 110,000 barrels a day?

Absolutely, Roger, you're spot on the mark.

If I was to look at the 35,000 barrels a day, BOEs a day, of production from horizontal wells, could you give me a sense of the percentage of oil and the number of net wells that that comprises?

Sorry, could you repeat the question?

Yes. So 35,000 barrels a day is the number you said, about 20% of your production was from horizontal wells. I'm just trying to get a sense of current production. What the number of net wells in that number, and the percentage of oil.

Okay. The general number would be about 700 wells. I'd split that, that it's fairly heavily dominated, I'd say 70%, 75%, is tied to shallower wells. So more tied to the Spearfish Viking and less tied to the Cardium Slave. We've been a little slower coming up the learning curve. Longer drill times. On a percentage of oil basis, I'd say we're roughly 75% oil and 25% gas. And that's not any emphasis on gas projects, believe me. That's strictly the GOR and associated gas with the oil that we're producing. So 75%, 80%, would be a rough number.

Okay. I think you've answered this, Hilary, on the Q2 volumes. But it sounds like peak shut-in volumes from turnarounds would be in the 8,000 to 10,000 barrels a day range. Between that and, of course, breakup and other related tie-in,. Is Q2 production going to be flat or down a little bit from the Q1 volumes?

It's going to be down a little bit from Q1. We've got almost 5,000 barrels a day coming off at Weyburn. These are pretty big turnarounds. But, as we mentioned before, we've factored that into our overall plan, so nothing changes on an annual basis.

But, again, we really planned limited tie-ins. And the combination of that and the turnarounds, Roger, we really anticipate we will be shaded down in the quarter, but that was built into our thought process when we put out our guidance.

Yes, I just want to set expectations appropriately, is how I'll describe it.

(Laughter) Appreciate that.

Thanks for that one.

It's sort of unrelated, but you've given us guidance on volumes. Where do you think you'll be at the end of the year in terms of percentage liquids?

I'm going to say we'll be pushing, I'm going to say, 66%, 67% by year-end. And the reality is that if there is there's an asymptotic function here. Given that you're always going to be getting associated gas, our move towards higher oil, there's still a limitation of where you can absolutely get to. About the only thing we absolutely know for certain is that 100% of our cash flow will be coming from liquids.

Unless gas prices go up. Just a couple of real minor things here. Are you using rail at this point for oil sales?

We have some very limited -- very limited -- oil. We are looking at a couple of potential projects in a few select areas. It's not going to become fundamental to our business lines, we believe, however. It may be something that we can push up to 10% at some point in the future. But it's not something that's going to have an immediate effect on what we're doing.

Okay. And I think the last one here -- I'm trying to look at my notes -- if you look at your dual laterals in the Slave Point, and you're focused on waterflood longer term, does that give you a challenge in terms of are you looking for new injectors or conversion of dual laterals to injection?

I'm going to turn that to Bob Shepherd at EOR, because that's an ongoing debate internally, actually.

It's a great question. And we're having the dialogue right now with the development teams. I think ultimately it will emerge that if we stay with dual laterals, we will space them and lay them out accordingly so that they can be converted at intervals to water injection and get the ultimate sweep of efficiency. In some of the areas where we have already placed the wells, there will be some single laterals, probably spaced in amongst that. But if we keep going with the dual laterals, we will configure them in a way that allows them to be converted for water injection.

One important point, Roger, and I want to make this about all horizontals that will be used as injectors eventually. Is that given the royalty structure, it's going to pay for virtually every injector to pull out between 50,000 to 75,000 barrels of primary before we convert them. And it really strengthens the economics of any of the injectors we build in. And that takes about two years generally. But that will ultimately strengthen the economics of all our EOR projects on an overall basis.

And I don't think I have anything else. Thank you very much for your time.

Cristina Lopez, Macquarie Securities.

I just have a couple of quick questions. One of them is going to be on CapEx. And sorry to belabor the point. But a follow-on, on Jason and Gord's questions. With respect to the spending in Q1, it looks like it was, again, trending higher as far as drilling and completion spending in the first quarter versus the fourth quarter. Where do you see that trending? Because my question starts to become is, as you have to build up in inventory going into next year, as well, are you going to actually have to look at asset sales in order to meet your CapEx guidance?

To meet our CapEx guidance, no. We believe we have the capacity internally to do that. I think that broader question goes to that strategic point I think we started with early on. Which was the pace at which we're going to grow the machine. Ultimately we believe we can start to pick up that pace. So any asset sales from that would drive forward Q4, and carry forward volumes would be involved in the quickening of that pace of development and increasing our growth profile. That would be our general aim behind anything we do in the latter half of the year different from our current capital plan.

So, then to tie back on the production and the spend, how many wells do you have now as an inventory of wells that have been drilled and need to be tied in? And how does that compare to what has historically been an average run rate?

It's significantly ahead of our average run rate, Cristina. We're looking at -- I've got about 85 wells that are in inventory. And they will be tied in. They've been drilled and in various stages of completion. It's a deeper inventory than we've ever had. So, it's just really a conveyor belt now. But we've got certainly in the low '80s in terms of numbers of wells that will be drilled -- or, sorry, be tied in over the latter part. So the late part of Q2 and into Q3. Most of that we plan for Q3.

And this compared to a tie-in of 142 wells, is that right, during Q1?

That's right.

Okay, I think that's all I have for now.

Kyle Preston, National Bank.

It certainly seems to be a busy Q&A session this morning. But most of my questions have been answered. I just had one final question here. Just wondering if you can comment on the progress at your Peace River Oil Sands Project, in particular, that thermal pilot. And also when we would expect to see some meaningful volume contribution from that area.

Curious-- the same question I asked the gentleman who did the project. No, but all kidding aside, and the reason I say that, Kyle, is because we've basically just finished our second cycle of steaming on the sealed main well that had already been the top performer in the area. We're just starting to bring it back here in the last couple of weeks. We anticipate it is going to be another month or two before it reaches peak volume on that well. So we're very curious to see how it responds on a second cycle.

Beyond that, by Q3 this year, we're anticipating regulatory approvals on our Harmon Valley South pilot project, as well as some feedback on our sealed main commercial pilot project. So both of those are in the works. And then we would be into drilling hopefully by late '12, early '13, and starting to bring those ones around by spring, summer, of next year.

And when would that potentially lead into a commercial project?

I think basically either of those are the launching pads for commercial projects out there. And then it's just a question of we will probably, I would say, by Q3, '13, we're really starting, we'd already have our applications in for commercial and we'd be well into the ordering process. And then starting to do drill programs in '14 and steaming for later '14, '15 by the time you start to bring those on.

All right. Thanks for that.

We have no further questions at this time. I'll now turn the call back over to Mr. Murray Nunns, President and CEO, for any closing remarks.

I'd like to thank everyone for their attention this morning. It's quite obvious from the number of questions there is a lot of interest in how we're progressing the overall inventory and where we're heading. We believe we have that depth of inventory, that ability to execute on it. And as I think we have demonstrated in the past, we are quite willing to make the financial measures to allow us to drive the machine forward. So thank you, everyone.

This concludes today's conference call. You may now disconnect.