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Executives

Matt Taylor - Vice President, Capital Markets & Communications

Sveinung Svarte - President and Chief Executive Officer

Rob Broen - Chief Operating Officer

Kim Anderson - Chief Financial Officer

Analysts

Mark Friesen - RBC Capital Markets

Chris Feltin - Macquarie

David Taylor - Taylor Asset Management

Mike Dunn - FirstEnergy Capital

Jeff Jones – Globe and Mail

Chester Dawson - Wall Street Journal

David Simon - Twin Capital

Ashok Dutta - Platts

Dan Healing - Calgary Herald

Lauren Krugel - Canadian Press

Athabasca Oil Corporation (OTCPK:ATHOF) Q2 2014 Earnings Conference Call August 6, 2014 9:30 AM ET

Operator

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to Athabasca Oil Corporation’s 2014 Second 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) As a reminder, this conference call is being broadcast live on the Internet and recorded.

And I would like to turn the conference over to Mr. Matt Taylor, Vice President, Capital Markets & Communications. Please go ahead, Mr. Taylor.

Matt Taylor - Vice President, Capital Markets & Communications

Thanks, operator, and welcome everyone to our second 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 those advisories.

Joining us in the room today from management, we have Sveinung Svarte, Athabasca’s President and Chief Executive Officer. He will begin the call discussing the highlights for the quarter. We have Rob Broen, Athabasca’s Chief Operating Officer who will provide details on operations, followed by Kim Anderson, Athabasca’s Chief Financial Officer, who will present a summary of the financials, and then we will follow with a Q&A.

I will pass the call over to Svein.

Sveinung Svarte - President and Chief Executive Officer

Thank you, Matt. Good morning, everyone. I know you are all waiting for news on the Dover transaction. However, to make sure, we continue focusing on the operational results, which are the long-term key to success for Athabasca, we will go back to Dover once we have covered the operational side of the quarter. Our two main development activities, that Duvernay and Hangingstone 1 are both advancing very well and results are very good.

The light oil production averaged approximately 5,800 BOE per day, just above the midpoint of our prior guidance. We obtained extended production results from two additional Duvernay wells at Kaybob West. The 8-29 well has a restricted IP30 or approximately 800 BOE per day and 4-29 located on same pad has a restricted IP30 or approximately 600 BOE per day. The results from both these 1,300 meter long wells validate our interpretation of prospectivity from the volatile oil window, an area where we have substantial acreage. The results from our winter programs are very encouraging and we are seeing industry activity ramp up as to play transition to the development stage. In the thermal division, Hangingstone Project 1 is advancing as planned with construction expected to be completed around year end and first theme at the end of first quarter 2015.

I will now hand the call over to Rob Broen, who will present the second quarter operations more in detail. Please go ahead, Rob.

Rob Broen - Chief Operating Officer

Thank you, Sveinung and good morning to everyone. I am pleased this morning to provide an update on operations for both light oil and thermal oil. As you have seen, we have released a significant amount of detail in our press release, particularly on Duvernay results. So, I will review some of those highlights and I will provide some additional commentary.

As Sveinung mentioned, our light oil production averaged 57 BOE to 67 BOE per day comprised of 52% liquids in the second quarter of 2014. And this production is in line with the guidance we gave of 5,500 BOE to 6,000 BOE per day. This production included 17 days of downtime from third-parties and that compares to our planned downtime of 10 days. The total downtime in the quarter impacted our production by about 1,000 BOE per day on the quarter.

For the second half of 2014, our production guidance is estimated at 6,000 BOE to 6,500 BOE per day, which maintains a flat production profile for the rest of the year and it has our new Duvernay wells offsetting our base declines. A fall drilling program is not expected to add material production until 2015. The company realized a netback of $46.12 per BOE in the second quarter of 2014 compared to $36.93 per BOE in the second quarter of 2013. This increase is primarily due to higher commodity prices but also positively impacted by the increase in high quality liquids from the new Duvernay production. Liquids as a percentage of total production increased from 47% in Q1 of this year to 52% in Q2 2014. We expect this percentage to increase even further in the second half of the year.

I am now going to move on to some Duvernay operational results which we are pleased to discuss this morning. During the quarter we brought on-stream the final two wells that were completed from our winter 2013-2014 program. These wells were put in a plant soak period after initial completion. Further, the wells were drilled off to same pad locations, but intentionally drilled at different wellbore orientations. The first being a north-south orientation and the second drilled on strike over Northwest Southeast.

The objective of this test was to test wellbore orientation and monitor completions with micro-seismic to help determine optimal well placement and completion design. The first well 8-29-64-20 had a northwest southeast orientation and we soaked that well for 77 days. It had a restricted rate IP30 of 784 BOE per day with the condensate yield, the free condensate yield of 763 barrels per million. The second well and this well had the north-south orientation was soaked for 69 days. It had a restricted rate IP30 of 615 BOE per day with a free condensate yield of 710 barrels per million. The micro-seismic data and their early well performance suggest that one strike orientation may deliver superior results in this play.

The soak period tests were successful in both cases and they drilled at higher rates and pressures and lower water production. Both wells continued to flow at restricted rates and extended production plots are included in our IR presentation, which was posted this morning. These two wells were drilled into the volatile oil part of Duvernay fairway and are producing a high quality API condensate. The range is 46 to 48 API and that’s from the very over-pressured reservoir. The results from these wells are validating our technical interpretation and prospectivity from what we believe is the volatile oil window fairway.

We are seeing excellent rates from these wells and we think that’s primarily due to the over pressured nature of the reservoir. The Duvernay well located at 107, when we talked about this well at our last quarterly 1-7-64 20 West the fifth and that’s in Kaybob West, it continues to perform well at a restricted rate. Our average production for this well over the first 90 days was 625 BOE per day with a free condensate yield of 418 barrels per million. This compares favorably with the restricted rate IP30 a 750 barrels per day released in May for this well is holding it nicely.

Our Simonette, our well at 1-25-62-25 continues to be a top producer in the Duvernay fairway. Production through permanent facilities commenced in May and in the first 60 days, the well had an average restricted rate of 1,286 BOE per day with a free condensate yield, up 294 barrels per million. This also compares favorably to restricted rate IP30, a 1,461 BOE per day for the 315 barrel per million yield. This well continues to produce at a highly restricted situation. The company believes production cost issues have a considerable influence on the initial productivity and the ultimate recovery of these Duvernay wells.

In addition to post completion soak period and parts of the reservoir especially in the oil, volatile oil window the company also observes sustained production and managed pressure draw downs. By intentionally restricting our production rates we have dramatically lowered pressure declines with well production finding the sweet spot where decline rate is lower and wells were able to sustain higher rates for a longer period of time. I think our best example is our well at 2-34-62-20. That well is still to this day produces at a restricted rate after accumulative production of 341,000 BOE and approximately a year and a half of production. This well continues to be one of the best wells in basin to-date. We have one additional horizontal well that we drilled last winter and that’s in Simonette 16-36-63-25 and we will complete that well later this year once our capital budget is finalized. We expect to see production results from this well certainly early in 2015.

So I would like to say just a few words on cost. Athabasca anticipates a significant reduction in well costs as the play moves towards development stages. Cost learnings are well documented across North American shale plays. To-date, our well costs have included vertical strat tests, core work, larger 5.5-inch mono-board casing design and in some case micro-seismic monitoring. Additional strat and core work, including the additional strat and core work, our drilling cycle times from spud to rig release have averaged approximately 40 days with a minimum of 25 days. These results have been over a significant variance in TVD across the play. We are at 3,800 meters total vertical depth at Simonette, all the way up to 2,800 meters total vertical depth in East Kaybob. So, you can appreciate the variance in costs.

More importantly, our drilling rate penetrations have been consistently in top quartile performance in the basin and we have very tight operating ranges on these. Most of our wells have been drilled with only 1,200 to 1,300 meter horizontal lengths and we expect significant cost efficiency improvements with increased lateral length, while getting improving production results. As far as our completions, our design focuses on high rate large tonnage hybrid fracs and we use high strength to profit. While this is on increase as cost, we believe it has yielded superior results from our initial shorter lateral lengths. We will continue to advance our completion design and execution to minimize cost and deliver superior results. We are very confident in our ability to reduce costs, particularly with pad drilling and we expect horizontal well cost to be $10 million to $15 million per well in future phases of our drilling program.

So, overall, the focus of our Duvernay program to-date has been to retain land, prove the resource extent and understand the basin. In total, Athabasca has now drilled 8 horizontal Duvernay wells in the fairway, of which 7 were on production by the end of the second quarter 2014. The company holds 200,000 net acres of high graded Duvernay land, which contains greater than 20 meters of shale play and lie in the heart of the Kaybob Duvernay fairway. Approximately, two-thirds of our Duvernay acreage is extended into the intermediate term and additional five wells are required over the next drilling season to extend approximately 95% of our acreage into the intermediate term.

The next phase of our Duvernay program you can expect will shift prior to prioritizing production and cash flow growth from Saxon, Simonette and Kaybob West areas, where Athabasca and industry have demonstrated commercial well performance. Athabasca is fortunate to have material land positions across all the thermal maturity windows in the Kaybob area, particularly for a company our size. We are very pleased with our well results and we continue to be encouraged by industry results that is largely de-risking a big portion of the Athabasca land.

Quickly on the infrastructure side of the light oil business, in the second quarter of 2014, we completed the installation of a 10-inch pipeline that connects Athabasca’s Kaybob West facility to the SemCAMS’ KA Gas Plant. This project was completed as part of our Q4 2013 sale of 50% of our interest in our Kaybob infrastructure. We have retained a 10% working interest in this pipeline at no cost to Athabasca. Our production is now duly connected at two large gas to two large midstream gas processors in the Kaybob area and our liquid production is tied in directly to sales transportation system.

Our strategy of creating future optionality and scalability for the egress of our production in this area, while retaining control is intact. Athabasca is expecting a 10-day care outage in September and with the connection to the SemCAMS, we are well positioned to minimize the downtime from this shutdown and other third-party shutdowns in the future.

So, that concludes my comments on the Duvernay development. I am now going to switch to the thermal oil side of the business. In the past quarter, we made significant progress on the development of Hangingstone Phase 1. All 25 producer laterals and 25 injector laterals have now been finished and the reservoir quality as we said before is consistent with expected results derived from our extensive appraisal drilling and in reservoir modeling. The overall project is now 89% complete at June 30, 2014. Construction of the plant is progressing really well and is anticipated to be complete around the end of the year, with first team targeted towards the end of first quarter 2015. First production is expected to start approximately 4 months to 6 months after first team with production plateauing at 12,000 barrels per day in 2016. We are very excited about this milestone, which is just around the corner for us.

Cost from the overall Phase 1 projects are closely aligned with the sanction budget of $565 million for Phase 1. Including the additional well pad which was five well pairs and regional infrastructure, our total project costs are still estimated to be close to the previously disclosed $708 million.

We are evaluating potential options for the next phase of Hangingstone development. This includes an option to debottleneck the current Hangingstone 1 project for an increase of 8,000 barrels per day, which we will call Phase 2A followed by a 32,000 barrel a day expansion called Phase 2B. These options provide optionality for growth depending on future funding scenarios. Investment decisions will be made at a later date. Once we have demonstrated, production ramp up profile and have certainty on funding.

So that concludes my operations update. I am going to turn the call back to Sveinung for Dover update.

Sveinung Svarte - President and Chief Executive Officer

Thank you, Rob. So back to Dover Put, as you know Athabasca exercised its put option under the put/call option agreement on April 17 this year requiring Phoenix to purchase the confident dollar interest in accordance with the terms of the put/call option agreement. Both parties are jointly working towards the closing of the transaction and we have a mutually understood cost to closing including targeted timelines. We had hope this would have been done by now, but sometimes things take longer than anticipated.

As previously disclosed, the current net purchase price payable to Phoenix is $1,234 million. The company also made a separate provision for $49 million in respect to our potential settlement of certain claims made by Phoenix or identification under the PetroChina transaction agreement and the AOSC, MacKay’s share purchase agreement relation to future thermal abandonment costs associated with petroleum and natural gas, wells located in the Dover and MacKay River area. This is basically older gas wells. The company’s payment under this settlement is contingent upon successful closing of the dollar production. We are looking forward to provide EBITDA update of the process in the near future. However, to avoid unnecessary focus on specific dates, we will now provide further details on timing stage. We appreciate the ongoing patience from our shareholders and also from our employees who are all looking forward to closing this deal.

So with that, I will pass the call over to Kim Anderson who will present the summary of the second quarter financials.

Kim Anderson – Chief Financial Officer

Thanks Sveinung and good morning everyone. As mentioned I will provide a brief overview about Athabasca’s financial results and we will also provide an update on our capital spending and liquidity profiles for the balance of the year. For more detailed commentary on our financial results, I encourage you to refer to our financial statements and MD&A, which were filed on our website earlier this morning. In terms of financial results, Athabasca’s light oil netback for the six months ended June 30, 2014 was $45.1 million, an increase of 6% over the prior year. The increase was a result of higher realized pricing partially offset by lower production volumes due to base declines and higher royalties.

Fund flow from operations for the six months ended June 30, 2014 were $8.7 million compared to a loss of $6.9 million in the prior year due to the higher light oil netback, I just referred to as well as lower year-over-year financing cost and general and administrative expenses.

Turning to capital, year-to-date capital expenditures were $350 million including $22 million of capitalized G&A and $18 million of capitalized interest. During the second quarter, Athabasca spent $109 million including approximately $15 million for light oil, $91 million for its operated Thermal Oil assets largely relating to Hangingstone Project 1, just under $3 million for Athabasca’s 40% interest in Dover and 1% towards corporate assets. Our 2014 capital budget stands at $527 million. For light oil, total 2014 capital budget was $145 million of which $58 million remains to be spent in the balance of the year.

The majority of Athabasca’s remaining light oil budget will be spent in the third quarter on activities required to support in expanded Duvernay drilling program, which will be finalized following receipt of proceeds. For thermal oil, the 2014 capital budget for Athabasca’s operated assets is $348 million, of which $134 million remains to be spent. Balance of the year capital will be primarily directed towards completion in Hangingstone 1. We will also continue to advance regulatory work and preliminary engineering to support a potential future expansion at Hangingstone, which Rob spoke about earlier on the call.

Our 2014 capital budget also includes $20 million for the Dover joint venture and $14 million for corporate capital expenditures. Please note that the budget numbers referenced above exclude cash G&A expenses and capitalized interest. As we previously disclosed, capitalized G&A cost for 2014 are estimated to be approximately $50 million of which $22 million were incurred in the first half of the year.

As mentioned, Athabasca intends to provide a full update to its 2014 capital program and a preliminary 2015 outlook following the receipt of the Dover Put Option proceeds. In terms of liquidity, in the second quarter Athabasca completed a credit facility refinancing replacing its previous $350 million revolving credit facility with $425 million of committed funding.

The new facilities include a US$225 million term loan due May 2019 subject to the refinancing of our second-lien notes in 2017, a five year US$50 million delayed draw term loan, which we can draw at any time prior to May 7, 2016 subject to compliance with covenants and a three year $125 million revolving credit facility, which is currently undrawn.

The tenure of Athabasca’s new facilities provide us with better alignment with the development profile of our asset base and new credit facilities also contain more flexible covenants, which will facilitate our future business activities. As of June 30, 2014, Athabasca’s liquidity position was approximately $360 million including cash and cash equivalents, short term investments and funds available under our revolving credit facility and delayed term loan.

For the balance of 2014, Athabasca estimates it will have net cash outflows of approximately $260 million. Estimated net cash outflows includes the remaining 2014 capital budget, estimated G&A expenses and interest carrying cost offset by the estimated netback to be contributed by the light oil division. Net cash from this sale of Athabasca’s 40% interest in Dover will provide approximately $1.2 billion of incremental liquidity, which will be used to fund the development of Athabasca’s core assets, including the Duvernay and Hangingstone.

Athabasca closely monitors it’s near and long-term funding requirements and continues to evaluate funding alternatives to advance the development of its light oil and thermal oil process. We remain strongly committed to a disciplined approach to growth and building a stronger balance sheet and will only allocate financial resources and personnel to projects that are fully funded.

I would now like to turn the call back over to Sveinung for closing remarks.

Sveinung Svarte - President and Chief Executive Officer

Thank you, Kim. So, as we continue to move forward, we are focused on delivering on our priorities, which are first the completion of Hangingstone Project 1 targeted for around year end and the targeted Duvernay drilling and completion program, of course in addition to closing the Dover deal.

We’re also committed to a disciplined approach to capital expenditures, with the pending receipt of proceeds from the sale of our Dover investments and our new longer term credit facilities; we’re well positioned for profitable growth. Athabasca is fortunate to have excellent assets and a very motivated team. We look forward to releasing an updated corporate strategy with fulsome capital plans following the closing the Dover transaction.

So, with that we’re ready to take your questions. 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 Mark Friesen from RBC Capital Markets. Your line is now open.

Mark Friesen - RBC Capital Markets

Thank you. Good morning. Couple of questions for Rob first and then a couple for Sveinung. Rob, thanks for your update on the Duvernay. When do you expect to consistently reach targeted well cost below the $15 million target?

Rob Broen

Yes, Mark. So, like I was saying like all our wells so far have been single wells and I explained all the work and effort that goes into those. Our next phase of our drilling program, which we’ll release once we have a sanctioned budget here, is going to move towards pad drilling. And when you look at any shale play across North America is certainly a place that I’ve worked that’s what your step change comes in costs. And we have very specific plans that underpin that and we expect in the next phases of our drilling program to hit the ranges that I talked about, which are the $10 million to $15 million per well. And the reason I gave such a wide range is because when we work up at Kaybob East in 2,800-meter TVD wells that will be the low end of the range and when we work down in our acreage in Simonette, which is much deeper that’s the higher end of the range. So, I think that’s what you can expect to see from Athabasca in the next phases.

Mark Friesen - RBC Capital Markets

Okay. So, presuming this vintage program is larger than the five wells needed for land retention we should expect to see targeted well cost this winter?

Rob Broen

Correct.

Mark Friesen - RBC Capital Markets

Okay. Secondly, just a question on CapEx, it looks like the CapEx in the light oil division has gone up a bit and likewise the CapEx in the thermal division has gone down a little bit since the Q1 update. Could you provide some clarity on that?

Rob Broen

Well, Mark, I mean, our capital program in light oil is we finished the completion of our wells just like we said we would and the rest of the light oil capital is directed to preparing for a winter program and things like securing rigs getting long lead equipment like casing. And we are not going to fully embark on that until we have a sanctioned budget from our board. But our spending is largely in line with what we have been saying it was going to be. And on the thermal side, we certainly – we talked about Hangingstone cost quite a bit and that’s certainly in line with what we have disclosed previously. And as far as other thermal areas, we have reduced our field spending in some of those areas, because we are focused on Hangingstone 1 and operating that and we are focused on our Duvernay program.

Matt Taylor

Mark, it’s Matt Taylor here. The small kind of inconsistency to the Q1 budget was that we actually had a small approval for an expansion in late June that we provided in our updated corporate presentation and the magnitude was not material.

Mark Friesen - RBC Capital Markets

Yes, okay, thanks, Matt. Sveinung, just a couple of questions for you, if you could maybe provide a bit of history behind the discussion on the last settlement provision and any other adjustments or provisions are maybe being discussed or would remain possible at this time?

Sveinung Svarte

Yes, as we said in news release, this cost relate to a settlement of an indemnity claim relating to these old wells in MacKay and Dover area that needs or may need thermal abandonment. They are all legacy wells and quite numerous. We see that as development cost. However, in order to avoid future litigation on possible arbitration, we decided to settle out and we don’t see any material changes to the rest from the oil.

Mark Friesen - RBC Capital Markets

Okay. When did that discussion begin, Sveinung?

Sveinung Svarte

I think we started our discussion sometimes early Q2.

Mark Friesen - RBC Capital Markets

Okay. And I know you are clear that you don’t want to provide a lot of incremental discussion around the Dover Put Option, but I want to just maybe you could expand a little bit on what you mean by mutually understood path, like what are the steps remaining that need to happen for settlement?

Sveinung Svarte

Well, we don’t want to give you specific timelines, because I am basically fed up having my head to a gun for meeting certain deadline here, but definitely all the old lines or the steps, which document when should they be finished etcetera, including a targeted closing deadline has been set. So, I think we will leave it with that at the moment.

Mark Friesen - RBC Capital Markets

Okay, thank you. That’s it from me.

Operator

Your next question comes from the line of Chris Feltin from Macquarie. Please go ahead.

Chris Feltin - Macquarie

Good morning, guys. I guess this is probably more of a question for Rob. Just with regards to the two newest Duvernay wells up in the oil window, I mean, some of the analog plays like in the Eagle Ford as you move up into more of the oil window with those higher liquids yields recoveries tend to falloff. There aren’t really any pressures indicated in the press release today, but just curious what your interruptions are to-date in terms of flowing pressures relative to what you have seen a little bit further south. And if you can have any initial commentary on declines and what you think ultimate recoveries could be there relative to kind of the more condensate rich part of the play? Thanks.

Rob Broen

Sure. Well, I will just give you some of the things that we are looking at that give us – that make us feel pretty good about our technical interpretation. First of all, I mean, we think this is volatile oil certainly by the yields, I mean, it’s very high barrel per million yield. Certainly, if you compare to the Eagle Ford when you get into greater than 350 barrels per million, you start to get into the oil regions. The API gravity though of what we are producing is very high. We are seeing anything from on the very low end 45 API to up to 48 API. The color of our oil samples is orange, which is consistent with the volatile oil. We do have PVT work, so down-hole pressure volume temperature analysis from a couple of offsetting wells that tell us what phase we are in or at least predict what it is. Certainly, when you compare what we are seeing production wise with the rock properties that we measure, which may reflect in T-Max, TOC, hydrogen index, it’s pretty consistent.

As far as pressures, the one key thing here is that the entire reservoir is over-pressured. We have not seen a normally pressured data point in this area. Everything is over pressured and we are seeing just the tremendous amount of energy from that reservoir that’s really moving the liquids through the reservoir. So, one of seven wells have been flowing for over four months now, continues to flow at a restricted rate. I know the gas rates seem a little lower and people are concerned about that, but the reality is the tremendous reservoir pressure and all these other qualities that I mentioned are showing us what these wells are capable of. So, you don’t see the high flowing pressures like you do in the Simonette area, because it’s deeper, higher reservoir pressure, but for this area, it looks very good so far.

Sveinung Svarte

And I can add, Chris that we probably had not expected a 48 API as far north as this, as well as what we see from neighbor operators here at the moment. I think it looks like the well to oil, we now extend further north and we actually believe before you get into the black oil window. So, that’s all good news.

Chris Feltin - Macquarie

Okay, that helps a lot. Just kind of that API data clarification helps a lot in terms of with regards to the expectations or so? Thanks for that.

Sveinung Svarte

Chris. We also have some detail in an updated investor pack with pressures initial pressures in extended flow rates. So, we refer you to that.

Rob Broen

Yes, we put all the flowing pressures, both casing and tubing from our 30-day and whatever production data we have in our IR pack, so that it’s full transparent for you guys to have a look at.

Chris Feltin - Macquarie

Okay, great. Thanks.

Operator

Your next question comes from the line of David Taylor from Taylor Asset Management. Please go ahead.

David Taylor - Taylor Asset Management

Alright, thanks. Good morning. First of all, congratulations on the Duvernay drilling results, when I asked you on the $49 million reserve amount, is that – would that be your best estimate or would that be the amount that was agreed upon between you and PetroChina – would that be the agreed upon settlement or your best guess?

Sveinung Svarte

Well, that’s basically the settlement we are proposing and have reached on this issue and it has been negotiated.

David Taylor - Taylor Asset Management

Okay. And would that be – the negotiation of that settlement would that have been really the heavy lifting and really what you believe that would have caused the delay of the closing of the proceeds?

Sveinung Svarte

No, I don’t believe it’s really caused any delay. Of course, there has been a discussion, but the solution has been clear for sometime. There are various other reasons, which have caused additional time required, but I think most important for us is that we have two parties have mutually understood the path forward and to closing and including having targeted timelines.

David Taylor - Taylor Asset Management

Okay. So, given that you see any – other than normal closing events, you see anything out of the ordinary that’s what do you think would cause significant further delays or just between now and the state that you proposed you see normal closing events?

Sveinung Svarte

We see normal closing events from now.

David Taylor - Taylor Asset Management

Okay, thanks very much.

Sveinung Svarte

Thanks, David.

Operator

Your next question comes from the line of Mike Dunn from FirstEnergy Capital. Please go ahead.

Mike Dunn - FirstEnergy Capital

Good morning, everyone. Svein, I just wondered if you could elaborate at all on what aspects of the closing of this Dover Put Option have resulted and it’s taking longer than when you closed the MacKay Put Call transaction? And I have got a question for Rob after that.

Sveinung Svarte

Yes. There are various reasons why it’s taken longer. And I don’t think I will go into those details as I answered David Taylor just before you that the most important for us now is that we have a mutually understood path forward to closing on the targeted timeline. So, I think that’s all I comment on that.

Mike Dunn - FirstEnergy Capital

Okay. Maybe I will just try another one, Svein, when did you guys arrive at the mutually understand path to closing. I mean was that something from April or April, May or more recently.

Sveinung Svarte

No, it’s more recent on that, but I don’t give you deadline – a timeline that we will meet.

Mike Dunn - FirstEnergy Capital

Sure. Okay and Rob just wondering if you could – if you have settled at all on our targeted horizontal lateral lengths for your Duvernay program this winter, I think you mentioned was 1,200 to 1,300 meters is the typical lateral length that you have been drilling so far.

Rob Broen

Yes, that’s being the typical one of our wells offer the pad that I mentioned 29 well was a little bit longer. It was closer to 1,700 meters. But we are certainly a believe that longer is better in this area and for us we want to prove the resource first and demonstrate that we understood the reservoir and the characteristics of it. And to the next phase of drilling, we are going to be drilling some longer horizontal wells and particularly when you get into the oil window. And I wouldn’t want to say we have settled on a length, but our average length in the future is going to be longer than what we have drilled so far.

Mike Dunn - FirstEnergy Capital

Okay. And then so the targeted well costs are the – they are not apples-to-apples versus what you’ve been doing before they are the actual targets?

Rob Broen

Not necessarily, but a big part of the cost is just drilling vertical and getting to the horizontal section, right so.

Mike Dunn - FirstEnergy Capital

Sure.

Rob Broen

We see really good efficiencies once you get in the horizontal lateral. So, that’s what makes frankly drilling longer horizontal lateral is so compelling because you can create cost efficiency and for the OEs you get. So, we are preparing for that and not all our wells are going to be extended to reach long wells, but a few of them for sure will be.

Mike Dunn - FirstEnergy Capital

Great, that’s all from me folks. Thank you.

Operator

Your next question comes from the line of (Brian Galloway) from Scotiabank. Please go ahead.

Unidentified Analyst

Hi, this question is for Kim. I was just wondering if you could provide a snapshot of current cash and liquidity as of today and the extent if any more draw downs in your credit facilities? Thanks.

Kim Anderson

So I mean, in terms of our cash flow for the balance of the year, we can give you an estimate of what cash flows look like. I don’t have the exact balance today, but what I can tell you is in terms of our capital spending for the balance of the year. The $217 million that we have remaining to spend, we expected our 65% of that to be spent by the end of the third quarter. And then in terms of a cash burn rate which would incorporate our G&A cost, interest cost net of – are lighter on that back that’s running at about $22 million per quarter right now. So if you are looking at that I can give you pretty good estimate of what we would expect to end up towards the end of September and we’ll be sort of addressing along that path until that point.

Unidentified Analyst

Thanks.

Operator

(Operator Instructions) This concludes the analyst Q&A portion of today’s call. We will now take questions from members of the media. (Operator Instructions) Your first question comes from the line of Jeff Jones from Globe and Mail. Please go ahead.

Jeff Jones – Globe and Mail

Okay, well let me just try one more time, with regard to the timing of the closing of the Put. Would it be fair to characterize that something that has been caught up in the sort of broader Chinese political situation?

Sveinung Svarte

Well, we don’t know exactly the impact on that – on this case, I think what’s important to know is that with our partner we have a commonly developed timeline post closing and including the final date so that’s what I have to comment on that one.

Jeff Jones – Globe and Mail

Well, I have just sort of the changing as personal at the senior level there as a result of that?

Sveinung Svarte

Of course changing personal in any company with short note speed up the process, but I can always speculate what that has led to internal in PetroChina.

Jeff Jones – Globe and Mail

Okay, thank you very much.

Operator

Your next question comes from the line of Chester Dawson from Wall Street Journal. Please go ahead.

Chester Dawson - Wall Street Journal

Hi, guys, thanks for taking my call. I’ve got a couple of questions. First, have you been contacted by PetroChina in Beijing or the Chinese government in relation to an investigation that’s currently going on about CMPC’s overseas activities

Sveinung Svarte

This is not a concern for Athabasca. We conduct our business at the highest ethical standards and we are there to applicable laws and we are not in contact with anybody in this respect.

Chester Dawson - Wall Street Journal

Thank you. Also who exactly are you dealing with when you talk about being in contact with folks at CMPC, can you name any individual or individuals?

Sveinung Svarte

I mean, we have our formal contract to the joint venture arrangements and those names are publicly known or written about them. So, you probably have them already.

Chester Dawson - Wall Street Journal

I don’t. Could you please share at least one with us?

Sveinung Svarte

No, you can find them yourself out there on – we have our formal representatives in the joint venture and (indiscernible) PetroChina about that.

Chester Dawson - Wall Street Journal

Okay, great. And lastly, do you have any reason to believe that any of the early lease transactions in or around Dover had any in propriety in terms of who they were bought and so on?

Sveinung Svarte

As I said, it is not at all a concern for Athabasca. We conduct our business at the highest ethical standards and we are there to applicable laws and I know every single lease that were sold in those days, not the concern.

Chester Dawson - Wall Street Journal

Thank you. And actually finally just one last one if you would, I understand that you maybe obviously wanting to get the payment as soon as possible and you appear to have a timeline, if you do not get paid in the reasonable amount of time, would you consider legal action to force payment?

Sveinung Svarte

Obviously, we are not providing details on timelines here and we have different remedies we can pursue, but I don’t believe that would be an issue, because the signs from our partner is that we are going to close this in a timely manner and to the timelines we have developed together.

Chester Dawson - Wall Street Journal

Thank you.

Operator

Your next question comes from David Simon from Twin Capital. Please go ahead.

David Simon - Twin Capital

Hi. I understood your wording on the release is a little different than that release you put out last week regarding PetroChina and the closing of the Dover. Did PetroChina first give you permission to go into more detail here on areas and they are fully aware of what you put out here?

Sveinung Svarte

Like in most joint ventures, partners have to review and approve each other’s public communications about anything the joint venture. So, obviously that’s the case in this joint venture too.

David Simon - Twin Capital

So, basically they approved your press release?

Sveinung Svarte

They will just review what we state in public.

David Simon - Twin Capital

Okay. And when you talk about the transaction closing, we are not talking about a matter of several months, we are talking about was there a reasonable timeframe I assume?

Sveinung Svarte

Obviously, there is another timeframe definitely.

David Simon - Twin Capital

And it could be weeks or maybe slip a little more than that I would imagine?

Sveinung Svarte

I will (indiscernible) when we said we won’t come in detail from the closing deadline.

David Simon - Twin Capital

Okay, thank you.

Sveinung Svarte

Thanks.

Operator

Your next question comes from Ashok Dutta from Platts. Please go ahead.

Ashok Dutta - Platts

Hi, Sveinung thank you. Assuming that the PetroChina deal does come through, you have a couple of options to play around with, would your focus be after that on Hangingstone or on Duvernay?

Sveinung Svarte

Well, Duvernay is our number one priority, because it does provide short-term production and cash flow. Hangingstone 1 we are completing. We have the funds allocated for that. So, that’s another variable and piece for us. After that, we are surely looking at things like the Hangingstone 2, but definitely Duvernay is the first one here. And that’s where most of funds will go, won’t sit in the back.

Ashok Dutta - Platts

Okay, thanks.

Operator

Your next question comes from the line of Dan Healing from Calgary Herald. Please go ahead.

Dan Healing - Calgary Herald

Thanks. Good morning guys. I just had a question clarification on the $49 million being set aside, it was mentioned that there was a potential claim, but it’s a little unclear to me. I assume that the claim would be from the owners of those old gas vessels. Is that a done deal or is that something you are negotiating?

Sveinung Svarte

I don’t know, it’s actually claim from Phoenix for the development of these areas. These are wells that we will have to be or may have to be re-abandoned as a part of developing side being the area. So, it’s not from the old legacy. All of this is from – is between us and Phoenix basically.

Dan Healing - Calgary Herald

They are putting aside that money to provide for a future settlement of some kind?

Sveinung Svarte

No, no this will be development cost for them, if they re-abandon all these wells.

Dan Healing - Calgary Herald

Okay. Do they own those wells?

Sveinung Svarte

I don’t know exactly status about that, but some are owned by third-parties, some are owned by us et cetera, it’s a complicated ownership out there for the gas rights.

Dan Healing - Calgary Herald

Okay, so it’s not a party other than yourselves or Phoenix?

Sveinung Svarte

No, that’s correct.

Dan Healing - Calgary Herald

Okay, thanks very much.

Sveinung Svarte

Thank you.

Operator

And your final question comes from the line of Lauren Krugel from Canadian Press. Please go ahead.

Lauren Krugel - Canadian Press

Good morning. I know in the past, you have talked about doing a joint venture in the Duvernay, just wondering if that process has ceased for now, is that’s on hold for now?

Sveinung Svarte

No, our joint venture efforts continue. For us, this is a potential mechanism to help reduce risk and accelerate development and we leverage – growth leverage partner experience. So, as we had long development operation in light oil, we tried to have partners, but we have always said as well we need to close the Put Call before and continue the – and complete work on that, but definitely it’s continuing.

Lauren Krugel - Canadian Press

And obviously the joint venture in the Put Call with Dover and PetroChina has not gone smoothly so far, so what have you learned from this experience that you could carryover into future joint ventures that you might undertake?

Sveinung Svarte

I think every joint venture is different and it’s very hard to say that we have learnt anything from this one. There were lot of unforeseen events initially about a year and a half ago in Dover and obviously the Duvernay is very different, developments are completely different, approval process is very different. So, I don’t think we have had any negative experience that we will take with us on this. So, there is no learning from that basically.

Lauren Krugel - Canadian Press

Okay, thank you.

Operator

Mr. Taylor, there are no further questions at this time. Please continue.

Matt Taylor - Vice President, Capital Markets & Communications

Thanks everyone for joining us today and we will look forward to updating you in the future. Thanks.

Operator

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

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Source: Athabasca Oil's (ATHOF) CEO Sveinung Svarte on Q2 2014 Results - Earnings Call Transcript
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