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Executives

Andre De Leebeeck – Vice President, Investor Relations

Sveinung Svarte – Chief Executive Officer

Brent Heagy – Chief Financial Officer

Bryan Gould – President

Rob Broen – Senior Vice President, Light Oil

Analysts

Mark Friesen – RBC Capital Markets

Matthew Taylor – National Bank Financial

Michael Dunn – FirstEnergy Capital Corp.

Eric Busslinger – Marret Asset Management

Roger Serin – TD Securities

Matthew Taylor – National Bank Financial

Peter Ogden – Bank of America Merrill Lynch

Athabasca Oil Corporation (OTCPK:ATHOF) Q1 2013 Earnings Call April 30, 2013 9:30 AM ET

Operator

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to Athabasca Oil Corporation’s First Quarter 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) As a reminder, this conference call is being broadcast live on the Internet and recorded.

I would now like to turn the conference call over to Andre De Leebeeck, Vice President, Investor Relations and External Communications. Please go ahead, Mr. De Leebeeck.

Andre De Leebeeck

Thank you, operator. And welcome, everyone to our first quarter conference call. I would like to refer you to the advisories and forward-looking statements located at the end of today’s news release. All information provided today is qualified by these advisories.

Sveinung Svarte, Athabasca’s Chief Executive Officer, will begin the call discussing the current state of the business and recent events. Brent Heagy, Athabasca’s Chief Financial Officer, will then present a summary of the Q1 financials followed by Bryan Gould, the Company’s President, who will provide an update of our Thermal Oil and Light Oil divisions’ activities. Sveinung will deliver closing comments, before we begin the Q&A portion of the call.

Also in the room, our Rob Broen, Senior Vice President of the Light Oil division and Rick Koshman, Vice President of Projects & Thermal Operations. Please proceed Sveinung.

Sveinung Svarte

Thank you, Andre. Good morning to everyone. The first quarter has been one of the accomplishments for Athabasca, but we also have experienced our share of challenges. As you know on April 23, the regulatory increments for the Dover commercial joint venture projects, closing arguments represented yesterday. All parties tried very hard to reach satisfactory arrangement with the local stakeholders. And in this case, we just could not find a solution. I’m proud of the joint Dover OPCO team and the job they did during the hearing, by presenting the merits of development of the Dover area. I remained confident that Dover will receive regulatory approval for commercial development this year, and it’s great to do business in Alberta, where there is such a well developed regulatory huge process, a decision is expected within 90 days time.

In the thermal oil division construction at Hangingstone Project 1 has started proceeding as planned. Appraisal programs due to further dividend bitumen resources for the Hangingstone 2 projects on Dover West Sand continue along with a third production phase of the Thermal Assisted Gravity Drainage, TAGD Leduc Pilot and demonstration project at Dover West Carbonates.

The Light Oil division continued its further development oils production capability and commissioning all the infrastructure assets in the liquid rich of the Alberta basin. Production in the first quarter averaged 600,100 barrels of oil equivalent per day, which was comprised of approximately 56% liquid.

As previously, reported Athabasca’s daily production was curtailed during the first quarter of 2013, by constrained in a third party transmission line in the Kaybob East area and by significant service interruptions at the Keyera Simonette gas plant. We’re pleased with the high liquid content or gas. But it has contributed to the near-term difficulties in achieving steady run-time at the Simonette gas plant. We’re working closely with Keyera to achieve continuous and predictable operating performance and Bryan Gould will come back to this later in this topic with further details.

Athabasca continues to be encouraged by the strong performance of its initial three Duvernay horizontal vessels. We see very high drilling activity all around this and we are encouraged by the industry results. Our neighbors includes major operators with significant resource play experience.

I would like to turn the conference call over to Brent Heagy, he will provide a review of the Q1 financial.

Brent Heagy

Thank you, Sveinung, and good morning, everyone. During the first quarter of 2013 Athabasca’s light oil division, earned a net back of CAD17.9 million from an average production of 6,100 barrels of oil equivalent per day, which was comprised of 56% liquids as compared to CAD10.8 million in Q4 2012 from approximately 4,100 barrels of oil equivalent per day, which was comprised of 43% liquids.

Athabasca continues an active capital program during the first quarter of 2013 with total capital spending of $264 million. Spending was comprised of CAD176 million in the light oil division and $84 million in the thermal division with the remainder allocated to corporate.

As of March 31, 2013, the Company has CAD757 million of cash, cash equivalents and short-term investments on hand. Athabasca also has CAD200 million revolving credit facility available. We are confident of realizing the proceeds of CAD1.32 billion from the Dover put option in Q4 2013. Outside of that we have sufficient funding for the remainder of 2013 and we also have various options to enhance our liquidity if needed.

Options that we are currently accessing include joint ventures, which are an important source of financing and continue to be a core part of our growth strategy. As we developed the resource base in our light oil business, we can expand the borrowing base component of our credit facility. We may access debt markets by their increasing revolver or additional debt issuance. We are also exploring raising additional funds using the put option as security.

Finally, we have existing assets that could be monetized such as infrastructure. These types of transactions would be a normal part of business as we optimize our portfolio of asset.

In summary, there are several options that we have to enhance liquidity if there was a delay in receiving the proceeds from the foot option.

I’d now like to turn the conference call over to Bryan Gould, who will provide a detail about update about the progress in advancing at thermal oil and light oil assets.

Bryan Gould

Thanks Brent. In our thermal oil business, I’m pleased to report that our first oil sands development in Hangingstone is off to a solid start. In the field, 66% of the earthworks required for the construction of the central processing facility and well pads has been completed. A core part of our project delivery strategy going-forward is to be construction driven which means that we will ensure that key pieces of work are in place before we mobilize for mechanical construction in the field.

On this train, detailed engineering is a key component and we’re pleased that we are on schedule with 83% of the detailed engineering complete. For chemicals, hand in hand with this and it is also on schedule and on budget. Last but not least we expect to start drilling operations by mid-year to drill the SAGD well pairs.

In our recent oil sands winter evaluation program, Athabasca has drilled 23 appraisal wells at Hangingstone project to further delineate the (inaudible) resources. Our result confirm our geological models and we anticipate submitting regulatory application before mid-year for Hangingstone projects two and three which would increase overall production in the areas greater than 80,000 barrels per day.

We are also pleased to be advancing our transportation infrastructure at Hangingstone. In the first quarter of 2013, Athabasca entered into an agreement with Enbridge Pipelines for the transportation and terminaling of dilbit bitumen, a new 16-inch diameter, 50-kilometer pipeline is expected to be in service during the latter half of 2015. This would be concurrent with the planned production ramp up from Hangingstone Project 1. The pipeline is expected to be have sufficient capacity however to transport to company’s additional 40,000 barrels a day of dilbit, which is anticipate to come from Hangingstone Project 2.

Prior to operation of the dilbit pipeline, produced bitumen will be truck to market. At Dover West, we continue to position for material growth process in both the sands and our massive Leduc carbonate holdings. In essence, the company drilled and cased three delineation wells to further evaluate bitumen resources in the oil sands reservoirs. The drilling results further validate the resources required to develop an initial 12,000 bbl/d SAGD Dover West Sands Project 1.

In the carbonate, in the Leduc formation, Athabasca successfully completed its third production phase utilizing the innovative TAGD technology that Sveinung referred to earlier. Many of you will recall that the reef has very permeability and is up to 150 meters thick. We believe that the (inaudible) quality allows for a more general heating process than conventional SAGD processes.

Based on our field results, the company now concludes that is in deep feasible to produce bitumen through gravity drainage at temperatures considerably lower than those used in SAGD operation. The next step for us will be a large scale pilot to provide confirmatory direct field measurement of key economic parameters such energy balance and recovery factors.

Turning next to our Light Oil Division, in the first quarter of 2013 Athabasca advanced the developments of its light oil assets in the Kaybob area and continued exploration activities on its newest light oil assets in the Caribou and Muskwa areas of northwestern Alberta. Athabasca’s wholly-owned pipeline interconnect from Kaybob East to Kaybob West was commissioned in early April, allowing previously curtailed production and additional wells to come on stream.

During the first quarter of 2013, production averaged to 6,100 BOEs per day and was comprised of 56% liquids. As previously reported, our daily production was curtailed during the first quarter by constraints in the third-party natural gas transmission line in Kaybob East area and significant service interruptions at the Keyera Simonette Gas Plant.

Keyera completed repairs to the sulphur facilities at its Simonette gas plant in early April. However, the plant has continued to be restricted with respect to sour gas processing and liquids handling. This has reduced its ability to handle higher than expected liquid content in the gas stream feedstock from Athabasca’s liquids-rich Montney and Duvernay formations. We’ve been working closely with Keyera to resolve the situation and Keyera has recently made several upgrades at its Simonette plant and plans additional modifications throughout the second and third quarters of this year, including its scheduled shutdown in September 2013.

Athabasca continues to estimate maximum production capacity based on new well tests and production performance absorbed thus far of greater than 11,000 barrels of oil equivalent a day. We may face near-term production constrains until the Simonette plant has completed its plant modifications and is better able to handle the composition of the natural gas currently being delivered to the plant. We like everyone to keep in mind that the plant was originally designed to handle a different gas stream. It’s a large solid plant that is now running at minimum sulfur turndowns as emerging suite liquid rich plays are developed. The service interruptions that we’ve experienced are really around the three areas.

Firstly, the sulfur plant recoveries in which the plant was unable to achieve its licensed sulfur recovery of 96% in the first quarter of this year. As a result, the plant was shutdown on February 22, so that repairs such as the changing on catalyst bed could be need to improve recoveries. The sulfur plant resumed operation in April 1 and is currently meeting license software recoveries.

The second issue in plant relates to stabilization of liquids. The inlet gas stream is rich in hydrocarbons to drop out the required stabilization to be stored when comes to market. This requires heat from a sulfur plant in order to operate efficiently and clearly with the sulfur plant downtime, this is impacted the ability of the plant to stabilize the liquids.

Thirdly, our inlet liquid handling capability remains a significant issue in the near-term. A significant amount of liquid drops out in our pipeline as it’s transported from our well hedged to the Keyera facility. During startup, we conducted an operation called pegging in which we sweep the liquids out of line and this results in essentially a large patch of liquid arriving at the inlet of the Simonette plant.

The liquids that have to be handled are significant and it has been difficult for the plant to handle such a large amount of liquids as its front-end. Our concerns are now largely results around the liquids, our concerns now center largely around the liquid handling capability. We are working with care on several modification of their plant, which include additional storage and heaters to help stabilize the liquids and many of these modifications will be done this summer.

Further there are modifications being made at the plant in the scheduled turnaround in September to further elevate bottlenecks. All this work-ups to minimize the potential of further service interruptions, but we do anticipate continued production variability until the issues are firmly resolved. Athabasca’s production has been ramping up since April 1. As I said earlier, April months to-date is at approximately 5,800 boe’s per day, but our range has been very wide with days as low as 300 boe’s a day and as high as 9800 boe’s a day on the daily basis.

We’ve at least two set backs at the Simonette plant in April with handling our liquids production. Each time there is one of these setbacks it takes a significant amount of effort to get the wells back on production again and this takes some time, but we are making progress. I want to conclude our comments on the plant by underscoring the fact that we have a solid working relationship with Keyera and we’re confident in their ability to identify and implement the modifications necessary to adopt the Simonette facility handle the new play specifications.

In parallel to this plant work Athabasca is working hard on also processing its fluid. We are working hard to optimize our wells and in fact have now installed artificial lift on 80% of our wells.

We will take steady run-time to fully complete this optimization. Further, our wells have limited production history, so we have not established (inaudible) to be able to predict future performance. We are focusing on getting stable operations up and running at which time we will get a much better handle on the ultimate capacity of the field.

During the first quarter of 2013, Athabasca drilled 16 horizontal development wells in Kaybob area targeting the Montney formation, an additional three Montney horizontal wells are scheduled to drilled in the second quarter of 2013. At a total of 18 Montney horizontal wells were completed during the first quarter with an additional 7 wells scheduled for completion during the second quarter of 2013. All the Montney wells from the winter development drilling program are expected to be tied in and producing by the end of the second quarter of this year.

One successful water injection well was also drilled and completed during the first quarter in the Kaybob East area. All this is to say that we’ve continued to add to our production capability in the field and this underpins our estimates of future production. We continue to be encouraged by the strong performance of our three Duvernay wells and the company is also encouraged by Duvernay production wells supported by other industry operators. Athabasca drilled 350,000 high graded acres of liquids rich Duvernay potential including 200,000 net acres near Kaybob, which contains greater than 20 meters of net pay and this lies in our view in the heart of the Duvernay Fairway.

Athabasca believes that it has more than 2,000 potential drilling locations in the Montney and Duvernay formations. The Company intends to conduct a major review of its 2013 capital budget directed towards these opportunities.

I’d like to now turn the conference call back over to Sveinung Svarte, who will continue with closing comments before we take the Q&A portion of this call.

Sveinung Svarte

Thank you Bryan. So as you have heard the first quarter of 2013 has been challenging with respect to growing our light oil production in the Kaybob area. Like other operators we have experienced growing pains with infrastructures as we bring all the new liquid rich play on stream. But we are moving forward and we are excited about the potential of our Montney and Duvernay assets, and I am confident we will deliver the results we expect.

Now for the thermal oil division, I’m proud of the team who are in the process of building our first SAGD project. It is an experienced team recruited from the very best SAGD operator and they are progressing as planned for our first Oil Sands production early 2015, the project we are now in the field building. What I’m not so proud about is our recent stock price performance. We have not yet finalized an Oil Sands joint venture, although we are still working on it.

So we expected to be discounted for that. What is more surprising is the way we seem to have been discounted when it became clear that the public hearing was needed in order to achieve regulatory approval for the Dover joint venture project hearing which was completed yesterday.

Public hearings are often parts of the regulatory approval process in Alberta. In hindsight, we probably could have been all done a better job in explaining to the world that approvals normally are granted as a result of this process and also in explaining the difference between Alberta and some other provinces in Canada, let’s take a look at all the projects for a long period.

Nevertheless, we are now looking forward and it’s all about delivering our milestones, which include, of course, Dover regulatory approvals and further joint ventures. In addition to the fact that for Athabasca, it’s now all about project execution, Light Oil already built a large 100% own infrastructure system and it’s delivering the production.

The Oil Sands team is also progressing as planned and we will refer Oil Sands products at Hangingstone, in addition to advancing the further phases of Oil Sands production both in Hangingstone and Dover West areas.

So with that, we are now ready to take questions. So operator, please announce the first question.

Question-and-Answer Session

Operator

Thank you. Ladies and gentlemen we will now conduct the analyst question-and-answer session. (Operator Instructions) And your first question comes from the line of Mark Preston with RBC Capital Markets. Your line is open.

Mark Friesen – RBC Capital Markets

Thank you, Good morning. Just a few questions, gentlemen. You talked about a little bit, Bryan, but maybe in a different context, can you just summarize how many wells you currently have completed and standing that are awaiting tie-in and how many more are awaiting completion?

Rob Broen

Good morning Mark, this is Rob Broen here. Yeah, just as Bryan mentioned, we, in the first quarter we drilled 16 Montney horizontal wells, and so in total light today, we have just over 16 Montney horizontal wells. And in addition to that we have three Duvernay wells. We have seven more wells that we’re going to complete into Q2 and we expect all those wells on production by the end of Q2. So that’s the summary of our inventory.

Mark Friesen – RBC Capital Markets

Okay. Assuming favorable ruling from the ERCB hearing, how long would you expect it to take to receive the payment from the put following that event?

Sveinung Svarte

We expect once we actually get regulatory approval which would taken order in council, it would probably be four to five weeks we’d anticipate before we would receive the proceeds from the put option.

Mark Friesen – RBC Capital Markets

Okay, great. And then looking at it maybe a different way assuming that you don’t have the approval from the hearing by mid-year, how comfortable would you be reviewing and increasing your CapEx at that time?

Rob Broen

Mark, are you saying approval from the, or ruling from the panel or…

Mark Friesen – RBC Capital Markets

Yeah, that’s right. If they take their full 90 days, would you wait hear that from that or would you feel comfortable reviewing your CapEx before you here back you the ERCB?

Unidentified Company Representative

Well, I think we are first reviewing the well results, but as you know the amount we have enough steady running time for long time now. But obviously mid-year this year we will look at the situation on I think Brent talked about several tools in the tool box there have additional funding. So, I think it depends on where we land on all this, but I think it’s probably safe to say that if we do go ahead with the larger program, second part of this year in light oil, it probably will be concentrated around two NF wells. (Inaudible)

Unidentified Company Representative

Yeah, I will just add to that, I mean obviously our focus right now is getting stable operations out of the Montney well. So Brian described the infrastructure interruptions we had. And so we’re trying really hard to stabilize our production and optimize those wells. And our preference would be to monitor in a really established type curves. Having said that, we are very pleased with the Duvernay results that we have from our wells and we’re pleased with what industry is reporting and we would be keen to start a Duvernay program, obviously, to further delineate our acreage. And we’re going to do a mid-review of that mid year, mid-year review and we will make decisions after that.

Unidentified Company Representative

I think Mark the point is that the panel decision is going to be an extremely important milestone for us, yes it is.

Mark Friesen – RBC Capital Markets

Okay. Changing gears just to take the, are you comfortable providing any rates in the last cycle and any details regarding the pilot that you talked about, like timing or cost?

Unidentified Company Representative

So on the rates no, not comfortable commenting about that, Mark. I mean, it’s a two-well very modest scale, but what we’re really excited about is we’re convinced that we’ve seen no gravity drainage between the two well bores, and that was the key for us to establish in our own minds, that the process works. In terms of scale of project, it’s fairly large in its extent. We have asked the team, money isn’t infinite as you know and it doesn’t grow on tree, so we have asked the team to sharpen their pencil and see of different ways we can reduce the cost and scope but that comes with trade-offs. Order of magnitude, it’s probably on the order of $300 million, so it is a large scale pilot.

Mark Friesen – RBC Capital Markets

And when would you be looking to make a decision on going forward with that?

Unidentified Company Representative

I think probably later this year, Mark.

Mark Friesen – RBC Capital Markets

Yeah.

Unidentified Company Representative

Yeah, it’s a big pilot and we want to make sure we’ve got it right and we would go into it making sure we’ve done our home work. So we have to in our minds be convinced that it’s got a very high chance of success and we kind of make sure we do our home work before we take on that commitment.

Mark Friesen – RBC Capital Markets

Right.

Unidentified Company Representative

And of course we wouldn’t go ahead with that until we have a clarity on the (inaudible).

Unidentified Company Representative

Correct.

Mark Friesen – RBC Capital Markets

Right. Okay and just finally from me, I just noticed that G&A was quite high in the first quarter, probably included some unusual items, can you provide some guidance as to where you think that G&A is going to settle in for the coming quarters?

Unidentified Company Representative

Yeah, well, first, Mark, it’s Brent Heagy. I’ll address sort of why it’s high. Included in there is about $2.7 million of some cancellation cost, which related to cancellation of a rig assuagement program and a camp, and that was related to a reduced program last winter in Dover West and we did that to better align subsurface activity with our development plans. So if you exclude that, call that a one-time item, we’re really essentially back on budget where we thought we would be on G&A.

Unidentified Analyst

So about $50 million a quarter then, we could expect?

Unidentified Company Representative

Yeah.

Mark Friesen – RBC Capital Markets

Okay. All right. Thank you, gentlemen. That’s it from me.

Operator

Your next question comes from the line of Matthew Taylor with National Bank Financial. Your line is open.

Matthew Taylor – National Bank Financial

Good morning, guys. Just a two quick questions, first the timing to secure financing is pretty critical here. We have all seen this is kind of been the biggest issue weighing on the stock. Have you guys discussed a similar launch structure with PetroChina in terms of like prior deals, this would make kind of complete sense, if you guys were aligned longer term and we definitely have the financial capacity to do this?

Sveinung Svarte

Obviously Matthew, those are things we can’t discuss in public or to discuss with other parties, so without several options. And one Brent talked about earlier today, are just some of them, but I can’t comment about in detail.

Matthew Taylor – National Bank Financial

Just a second question, in terms of broader market sentiment Oil Sands are clearly orphaned right now and not getting appropriate value recognition. Do you guys look to adjust spending to kind of the high rate of returns light oil activities and potentially slow down activity in the thermal project at this point.

Brent Heagy

I think we haven’t had to make that trade-off. And I hope we don’t have to make it either in the few trades, if the coal comes on time. We believe that those two business lines are very well suited together. One had high rate of return, as you but it’s hard to keep going forever. The other one you build it. You’ve a cash flow basically for 30, 40 years. So they are very compatible for us.

Having said that if we have to make a choice sometimes yeah, it will be tempting to let Oil Sands and more light oil, I probably we’ll confirm that, but I hope we don’t have to get into that situation.

Matthew Taylor – National Bank Financial

Okay, thanks guys

Operator

Your next question comes from the Mike Dunn with First Energy Capital. Your line is open.

Michael Dunn – FirstEnergy Capital Corp.

Hi, good morning, everyone. Just maybe wondering if you can run through for me again, I guess, the potential scenarios over this regulatory you’re hearing. Obviously, the base assumption is approvals. Is it simply a decision of approve of reject or could there be, I guess, a third sort of contingent approval that might require additional delays. Thank you.

Bryan Gould

Hi, Mike. It’s Bryan here. I mean, the base case assumption, you’re right, is approval in our mind. The other end member is obviously rejection. There are in between scenarios where it’s approval with condition and that’s a pretty wide ranging band there. So, I mean, it could be everything from the black and white end members to all kinds of shades, grey in between. But I would reiterate Svarte’s comments that we think Dover OpCo had a very strong team and put forward a very strong presentation to the panel last week. And for those that are from the earlier with the process here in Alberta, I know it gets described a little bit sort of like a trial in the courthouse. It’s not really quite like that.

I mean, the panels are experienced members that really have a good appreciation for the industry and how it works. And when you playback how the hearing occurs, I mean essentially there is a cross-examination between the various parties, but the panel themselves also examine and interview those that are giving testimony. But we feel very good with the way the presentations went last week and just to reiterate Brent’s comment, we’re not trying to negotiate in public or anything like that here, but we’re pretty confident that the team did a very good job last week.

Sveinung Svarte

I think it’s important, as well, to add that approvals with conditions that normally conditions you actually make yourself during the hearing, and no such conditions were discussed. Of course in the applications itself that are mitigations to environmental items, access et cetera. And those are things we have committed to before, but during this process no extra conditions were asked for or even made by either party. So, I don’t think that would be an outcome of this one. So, this one would probably be either white or black and hopefully for us, as we believe, it’s going to be away.

Michael Dunn – FirstEnergy Capital Corp.

Okay. And just on, I guess, the Light Oil Division potential joint ventures, I believe previously you had discussed potentially seeking a joint venture for your Duvernay acreage, but not needing it for, I guess, your Kaybob Montney. Is that sort of still the base case, that it would be a Duvernay joint venture? Or are you looking at sort of a more all-encompassing Light Oil Division joint ventures? Thanks.

Bryan Gould

Hey, Mike. It’s Bryan here. So you’re going to get the broken record response, but we’ll talk about why we joint venture, as Brent talked about, that is core part of our strategy and our view is that’s the best way for us to fund our growth strategy, but we’re not going to comment on which assets, with who, timing, terms, conditions or anything of that type. So, we’re just not going to talk about those things.

Michael Dunn – FirstEnergy Capital Corp.

Sure, understood. Understood. I just thought I would try. But, understood.

Bryan Gould

I know. For us the priority is still the oil sand joint venture at this stage

Michael Dunn – FirstEnergy Capital Corp.

Okay. That’s all from me, thanks.

Operator

Your next question comes from the line of Eric Busslinger with Marret Asset Management. Your line is open.

Eric Busslinger – Marret Asset Management

Just going back to the comment of doing secured financing to the rights of the put call, can you guys give us a sense for the order magnitude of debt that you would contemplate the use of the $1.32 billion put.

Brent Heagy

Really – Eric, it’s Brent Heagy. Really not at that time, I think the magnitude of it would depend certainly if we got a positive result, let’s say at the end of 90 days from the ERCB, hearing that certainly would raise the confidence in terms of the receipt of the quick proceeds. So I think that would certainly help in terms of the amount that we could raise. But no, I do not have a definitive number that I can give you.

Unidentified Company Representative

Hi, Eric. We’re happy to hear from you, what you think about us because you guys are the experts on this.

Eric Busslinger – Marret Asset Management

Yeah. Well, it just goes back to order of magnitude. I mean when you think about the revolving credit facility, the existing notes and if you guys would want additional debts and putting that on top of the capital structure and how do you guys think about that ease of the – your liquidity position?

Unidentified Company Representative

Yeah, now definitely we will look at size and timing of this. But important to know is that we did cause this good call well, those are high yield. The older days last for just to keep the flexibility in the future just in case it was needed. But we’re happy to discuss with you, I think may be in private what you think about this as well and if you are interested.

Eric Busslinger – Marret Asset Management

All right, thank you.

Operator

Your next question comes from the line of Roger Serin with TD Securities. Your line is open.

Roger Serin – TD Securities

Thanks very much. Good morning everybody. Okay, our first question maybe for Bryan, the production for April was quite a range so and you’ve talked about some of the things you’re doing with Keyera. If you were to guess is that sort of where we’re going to be through the balance of, at least through Q2 and Q3 or do you expect it to do a little bit better than the average for April.

Unidentified Company Representative

I think, sorry Roger. I think we’re going to see continuous improvement here, you know it’s not sort of that there is one giant thing that gets put in and then it’s all fixed. There is a series of modifications that Keyera is making and has been making and as well I mean, we were working with them very closely on procedures, you know there are other ways we can pick our line that perhaps seems left liquid through in one concentrated trench that would help them get through the start-up. So, I think we’ll see continuous improvement here, but we’d like to air on the side of under promising and over delivering. So, there is still a kind of an upside or success case here, we think line out quite nicely and we reach steady state faster, we just don’t want to promise what we can completely control.

Roger Serin – TD Securities

Okay.

Unidentified Company Representative

But – just by way of example Roger, we’ve started up and we’re ramping up in the first couple of weeks of April, and I think we’re up like pretty close to 10,000 boe’s a day, so reached one of those peaks. We’ve hit the line, the plant was knocked down, so we need to shut all our wells dock in and start over again. I think we were up for another 8 days picking the lines, same thing happened again. So, it’s been quite volatile that way, but it does take us you know little bit of time to get the wells started back up because they’ve got the high liquid content, so we got to unload the well bores that takes a bit of time and but we are confident once we sort of reach this stable operating platform that Rob described we’ll be often away.

Unidentified Company Representative

The only thing I would add to that as Bryan mentioned a number of modifications that are going to be done over the summer and all of those are going to be helpful up to getting stable run time, so, Keyera is working at putting additional storage, putting fee drums in putting heaters into stabilize liquids and we think that was sort of right moves to make and we’re pretty confident that all of that is going to help us get to a stable run time, as they make the changes over the summer.

Roger Serin – TD Securities

Okay, I guess may be following up on that Bill, sounds like you’ve got about 80% of the wells have pumps on them now, all the same or are you trying a range of different pump options or any gas lift or any submersibles or some of the pump jacks?

Unidentified Company Representative

Yeah, we’re trying quite a variety of different artificial lift methods, we do have rod pumps in we are trying ESPs and some of our higher volume wells, we have two [powered] locations that were on utilizing gas lift and there is some wells that just float right down and don’t need artificial lift, so we need stable run time in order to optimize our artificial lift methods and that’s one of the things that we’re very anxious about, because we haven’t established our type curves and artificial lift is a key part of that strategy.

Roger Serin – TD Securities

Okay. Are there any changes, I didn’t see any changes to your CapEx guidance for the year and may be lining at sounded like you are low to make some changes at this point in you’ll maybe revisit at the middle of the year?

Unidentified Company Representative

We have expected that middle of the year and unfortunately we’ll do it again, but I think it’s pretty clear that more work if we added is going to be a due in the side and we’ll see we’ll come back in next conference call (inaudible) on that.

Unidentified Company Representative

I mean, I would add that Rob and the team have been working very diligently in the background on fuel development findings with Duvernay. So, it’s been ready to move in terms of picking location, we also understand kind of the long-lead items, there is some casing that has to be ordered. So everything is kind of being clearly in place, so we’re ready to turn the switch on when we judge the moment to be right.

Roger Serin – TD Securities

Okay. I just want to understand that Brent made a comment about liquidity, you were good through ‘13, would that suggest not good through part of ’14 or you just confirm that you are good through 2013, and you’ve got a range of liquidity options available after that?

Brent Heagy

Yeah, right now where we stand, Roger, is that with our current cash and short-term investment position, we see that will take us through to the end of 2013 and then getting into Q1 of 2014, our forecast would suggest that we are starting to dip into our credit facility. And then after that, certainly as we had mentioned, certainly we feel confidence in terms of receiving the Dover put/call proceeds or and with the work that we are doing on joint ventures and the discussions that we are having there that alternatively there’d be proceeds from there.

Roger Serin – TD Securities

Okay. I want to understand following up on one of the earlier questions on the hearing process, first of all, as it relates to negotiations prior to a decision by the ERCB, negotiations post a decision by the ERCB, is there anything that prevents you and the interveners coming to an agreement before the decision by the board or even post the decision by the board?

Sveinung Svarte

There is nothing theoretically stopping you from doing it between no under decision that’s true. Having said that we are not talking about more than probably two, three months here and whole likely that is going to be how we probably describe that’s fairly low.

Roger Serin – TD Securities

And so I understand the process, if and when the hearing decision is made then, is there an appeal process, and what does that look like in terms of how quickly a party can file an appeal and then what the implications would be as it relates to the Dover put?

Sveinung Svarte

So the appeal process with ERCB is that upon the panel giving its judgment the either party has 30 days within of that to ask for the right to appeal to the Alberta Appellate Court and then they decide whether or not that appeal can will be heard.

Roger Serin – TD Securities

They was such a recent attempt now.

Sveinung Svarte

Yeah, there was a recent filing on that where the appellate court had refused to hear the case.

Roger Serin – TD Securities

Okay and that was the (inaudible).

Sveinung Svarte

No

Roger Serin – TD Securities

Okay, that’s all my questions. Thanks very much guys

Operator

Your next question comes from the line of Matthew Taylor with National Bank Financial. Your line is open.

Matthew Taylor – National Bank Financial

Hey, guys just a couple of follow-up questions, coming back to financial flexibility, what percentage of capital is committed to Hangingstone over the next two years, is it possible for you guys to slow down there or have you kind of contracted to drilling guys and service guys.

Brent Heagy

Now, so there is still flexibility I mean clearly that’s something you not want to do Matthew, but we still have flexibility on Hangingstone

Matthew Taylor – National Bank Financial

And secondly, in terms of – what color can you provide in terms of oil sands packages that you’re currently marketing? Obviously, Birch becomes difficult to market in this environment with, say, a potential buffer zone precedent at Dover. Is that fair?

Sveinung Svarte

Well, I think this case we are going through here will actually provide a lot of clarity on Birch as well, which is another reason why we don’t mind seeing actually a hearing, ruling on it because, yes, you’re right. It should be very similar problem up in Birch.

Matthew Taylor – National Bank Financial

Okay. Thanks Sveinung.

Operator

Your next question comes from the line of Peter Ogden with Bank of America Merrill Lynch. Your line is open.

Peter Ogden – Bank of America Merrill Lynch

Good morning, gentlemen. Three questions for me. Back when you first encountered these problems with the facilities, you indicated that Kaybob interconnect was going to be commissioned with the Keyera resumption. I was wondering if you could confirm that. Also, confirm that all the facilities are up and running? And then, you did indicate that that would lessen the impact of third party facility constraints. Was that gas always going to go to Keyera, or was there some change around that, those facilities process – ultimately process the gas?

Rob Broen

Yes. So the interconnect that we talked about connected Kaybob East through the Kaybob West, all the way to Keyera. And I can confirm that that has been commissioned and it was commissioned in conjunction with the Keyera startup on April 1. So all of our gas now goes to the Keyera plant. There was – before we had that interconnect commission, the gas was flowing on a restricted basis to (inaudible) which was why we put in the interconnect, because that freed up the capacity to send it all to Keyera. So on our end we have all three batteries in the Kaybob region up and running. Our pipelines are all commissioned and the facilities are running well. Our interruptions and our variability is all about being able to handle with at the Keyera, Simonette plants and Bryan describe that in quite a bit of detail.

Bryan Gould

I think that.

Peter Ogden – Bank of America Merrill Lynch

So it’s just that the liquids aren’t dropping off, dropping out of the batteries and you’re getting additional liquids dropout between the batteries in Keyera?

Sveinung Svarte

Yeah, the majority of our liquids are dropped out in our facilities. So all the condensate and free liquids are dropped out in our facilities, and that process is working very well. The issue is, it’s still a liquid-rich gas stream that we send to Keyera, and we have liquids NGLs that dropout both in the line and through the process at the Keyera plant. And it takes a while to sweep those liquids out of the line particularly as you’ve been shutting for a while, and get back to continuous operation, and that’s what we’re trying to do now.

Peter Ogden – Bank of America Merrill Lynch

Okay. I’ll combine my second and third questions. You guys have already spent about $180 million out of the $235 million light oil budget. So in the second half, I mean, would you expect to be through that entire budget by Q2. And if so would any incremental spending come out of the heavy oil budget, or would it necessarily be an incremental spend. And then, on top of that would you be comfortable giving kind of a per well budget for the Duvernay wells if you do expand that program?

Sveinung Svarte

So on question two, Peter, I would expect that we would have pretty much gone through the budget by midyear, which was always our intention. You may recall that we described last year, the impact of kind of frankly the wet climate and weather in the Kaybob area. And so we deliberately would like to see lower activities in Q2 and Q3. It just simply is too expensive to work during the wet season. And so we would like to again ramp up in the fourth quarter, when it’s just more practical to do so. So that’s always been our intention and our plan basically regardless of funding and type curves and other things. I think you’ll see on an ongoing basis activity skewed into the winter season there.

In terms of our funding for that, I wouldn’t expect that it would come out of a Hangingstone budget, my best guess would be that we would seek in addition to the budget for that fourth quarter still yet to be determined clearly, but I – that’s the way I would see base case playing now.

Peter Ogden – Bank of America Merrill Lynch

And what you’re budgeting for Duvernay well cost these days?

Unidentified Company Representative

Since we haven’t finalized locations, yeah, that’s a little bit hard to say but that’s part of the deliberation goes into how much do you spread the wells out, how much do you grow on pads et cetera, et cetera. I think Rob can give you a better color, but there is still a fairly white band on that given that we haven’t finalized locations.

Unidentified Company Representative

Our first three wells averaged about $15 million drilling complete, and our focus we did strap test, we did some coring, our focus was to really make sure that we get the information we need to delineate the Duvernay, certainly see line of sight to cheaper well cost as we get into pad drilling repeatable design as we get into common water usage in the area. Certainly costs are going to come down like they do in every unconventional play in North America. So, but our focus is to make sure we get the quality in the wells and that we really understand sub surface from the Duvernay.

Peter Ogden – Bank of America Merrill Lynch

All right. Thanks. That’s all from me.

Operator

This concludes the analyst Q&A portion of today’s call. We will now take questions from members of the media (Operator Instructions) Your next question comes from the line of Dan Healy with Calgary Herald. Your line is open.

Unidentified Analyst

Good morning guys. I just wanted to follow-up a bit on the joint venture Hangingstone and Birch, I know you guys don’t want to talk about that, but I guess has the situation changed from the last time you were talking about, can you at least give us some indication on that?

Sveinung Svarte

Hi Dan. Has it changed from last time we talked? I can’t remember it all, but obviously…

Unidentified Analyst

Quite a while ago.

Sveinung Svarte

We are still working on arrangement in Oil Sands because that’s our priority area to get it done, the good news is that there is still interest for Oil Sands worldwide, got several players still looking and in size and quality that’s where they look for all of our assets are suited for that, so I think you have to have a little bit more patient and see where we end up.

Unidentified Analyst

And my other question was, you just mentioned that the Birch project might be affected by the same set of circumstances that affect the Dover project, can you explain a little bit more about that? Is that project also next to the Fort McKay (inaudible)?

Sveinung Svarte

Yeah, that area is also bumping up against the same First Nation lamp but on the North Eastern side, so I would assume that would be the case. So obviously we are interesting to see that will come of this one, how long it takes et cetera and the still be important forward strategy on Birch going forward.

Unidentified Analyst

And if they did win a buffer zone, would that affect the viability of the Birch project?

Sveinung Svarte

20 kilometer it would be expecting a lot of companies but no, but for us a buffer zone has never been given to anybody before and I think creates a very strange precedence in Alberta, but again the main bitumen accumulation is actually quite far from the reserve land, but we have some touching up against it.

Unidentified Analyst

Are you talking about Enbridge, sorry.

Unidentified Company Representative

I mean the other thing supporting growth here, you need to be such that – I mean, we have not consulted with the Fort MacKay on this yet and we have to give respect for them and our relationship with them. So I think we’re getting a little ahead of our headlights speculating on how they may or may not feel about future developments and we frankly owe it to the Fort MacKay and other stakeholders in the area that go through the consultation process before we make too many assumptions on it. It’s a way out. But just wanted to explain, I mean we purchase a huge area and it’s got lots of potential in our view. But we shouldn’t be trying to hazard gases as to what the Fort MacKay and others may or may not have in their mind.

Unidentified Analyst

Okay thanks.

Operator

(Operator Instructions) Mr. De Leebeeck; there are no further questions at this time. Please continue.

Andre De Leebeeck

Okay, so thank you for joining us today. Our call is now complete.

Operator

Ladies and gentlemen this concludes the conference call for today. Thank you for participating. Please disconnect your lines.

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