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Executives

Andre De Leebeeck – VP, IR

Sveinung Svarte – CEO

Brent Heagy – CFO

Bryan Gould – President

Analysts

Peter Ogden – Bank of America

Matt Taylor – National Bank

Mike Dunn – FirstEnergy

Roger Serin – TD Securities

Andrew Potter – CIBC

Eugene Vath – Scotiabank

Athabasca Oil Corporation (OTCPK:ATHOF) Q4 2012 Earnings Call March 21, 2013 9:30 AM ET

Operator

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to Athabasca Oil Corporation’s 2012 Year End 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.

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

Andre De Leebeeck

Thank you, operator. And welcome, everyone to our year-end conference call. I would like to refer you to the advisories and forward-looking statements located at the end of today’s news release.

Sveinung Svarte, Chief Executive Officer, will begin the call by highlighting Athabasca’s 2012 achievements. Brent Heagy, Chief Financial Officer, will then speak to the financials. Sveinung will then provide a status update of our light oil and thermal oil divisions’ activities. He will conclude by discussing our 2013 outlook prior to beginning the Q&A portion of the call.

In the room this morning, we are joined by Bryan Gould, Athabasca’s President; and Heather Douglas, VP Communications. Please proceed, Sveinung.

Sveinung Svarte

Thank you, Andre. Good morning, everyone. Athabasca had a banner year in 2012 achieving numerous corporate milestones and transitioning from a pure exploration company to an exploration and production company, with a balanced portfolio of light oil production and a wholly-owned thermal oil project under construction.

Some of our 2012 highlights from the thermal oil division include the following: receipt of regulatory approvals in October for the Hangingstone Project 1, a 12,000 barrel-a-day SAGD project. In November, the Board of Directors of Athabasca sanctioned a $536 million construction of the Hangingstone Project 1 in addition to $27 million for associated infrastructure. Construction is proceeding on time and on-budget.

Demonstration of proof of concept for the Thermal Assisted Gravity Drainage, TAGD production technology was made during two field test phases at Dover West, effectively heating the reservoir rock and bitumen in the Leduc carbonates.

In the light oil division, we are pleased to present several significant milestones for 2012. The completion of infrastructure, including a 63-kilometer long, 12-inch diameter trunk pipeline from Kaybob West to the Keyera Simonette gas plant and oil batteries at Kaybob West, Kaybob East and Saxon/Placid; total capacity of this infrastructure is 36,000 barrels per day of oil, and 48 mmcf per day of natural gas.

We also saw production ramp-up in the Kaybob area, during Q4 2012, as the wholly-owned infrastructure was commissioned. On December 17, 2012, the company achieved peak production rates of approximately 10,700 BOE per day with as much as 57% liquids.

During 2012, Athabasca drilled 46 horizontal wells and completed 44 horizontal wells, targeting unconventional reservoirs in the Duvernay, Montney and Nordegg formations.

Athabasca completed three excellent Duvernay wells of which the best, 2-34-62-20W5, while producing on restricted flow, in February and March this year, has averaged greater than 800 BOE per day, with about 63% liquids, at a flowing surface pressure of greater than 20 megaPascals. The well is still flowing at that rate, and could flow at even higher rate if it was opened up.

By year-end, 33 wells were on production. Athabasca’s well inventory included 22 horizontal wells, completed with multi-stage hydraulic fracturing awaiting tie-in and seven horizontal wells awaiting multi-stage completions.

In December 2012, Athabasca set this 2013 mid-year production guidance of 11,000 boe per day to 13,000 boe per day, and we maintain our guidance. The Athabasca family continues to grow. One of the greatest corporate achievements is the ability to attract topnotch professionals. We now have over 250 skilled employees working towards the development of Athabasca’s unconventional resources. The dedication and efforts of our staff have enabled Athabasca to achieve a considerable growth during 2012.

So for the financials, I wish to welcome Brent Heagy to our Athabasca family. Brent joined us as CFO in March 11, and Brent will go through the financials. So Brent, go on.

Brent Heagy

Okay. Thanks, Sveinung, and good morning, everyone. It’s certainly a pleasure to be a part of the Athabasca team. With the ramp up of production through its wholly-owned infrastructure, Athabasca embarked on the path of significant growth in revenues from its light oil division, earning a net back of $10.8 million in the fourth quarter of 2012 from an average production greater than 4,000 barrels of oil equivalent per day, which was comprised of 43% liquids, as compared to $1 million in Q4 2011 from approximately 400 barrels of oil equivalent per day, which was comprised of 35% liquids.

2012 was a year of heavy lifting for Athabasca with total capital spending of $1.1 billion, compared to $622 million in 2011. Spending was comprised of $611 million in the light oil division, including land, and $478 million in the thermal division, with the remainder allocated to corporate.

On November 19, 2012, Athabasca issued $550 million in senior secured second lien notes bearing interest at 7.5% per annum maturing in 2017. As at December 31, 2012, the company had approximately $1 billion of cash, cash equivalents and short term investments on hand. Athabasca also has a $200 million revolving credit facility available.

So with that, I will hand it back to Sveinung, who will discuss some of our first quarter 2013 activities.

Sveinung Svarte

Thank you, Brent. During Q1 2013, Athabasca continued its site preparation for the Hangingstone Project 1. Detailed engineering is now over 70% complete. All major equipment has been purchased with cost in line with budget.

Athabasca has also entered into an agreement with Enbridge Pipelines for the transportation and terminaling of dilbit produced from the Hangingstone Project 1, a 12,000 barrel-per-day dry bitumen project. The new 16-inch diameter, 50-kilometer-long pipeline for Athabasca’s Hangingstone Central Plant facility to the existing Enbridge Cheecham Terminal is anticipated to be in service in the latter half of 2015, just as the Hangingstone Project 1 production ramps up.

The new 16-inch Enbridge pipeline has sufficient capacity to handle additional and anticipated 40,000 barrels per day, which will come from the Hangingstone Project 2. The pipeline will be an important part of keeping transport costs down for Athabasca.

Utilizing the innovative TAGD technology, Athabasca successfully completed a third production phase in the Dover West Leduc carbonates, confirming the production of bitumen from between the two horizontal well bores indicating good mobilization of bitumen at temperatures at about 6 – 90 degrees Celsius.

In 2012, the company submitted a TAGD Pilot/Demonstration Project application to the Energy Resources Conservation Board. Very encouraged by the results of the third production phase at Dover West, the company will seek sanctioning from its Board of Directors, upon receipt of regulatory approvals, which are expected in 2013.

For light oil division, as previously mentioned in December of 2012, the light oil division achieved peak production rates of approximately 10,700 boe per day, with as much as 57% liquids. Subsequently, through January and February, the company experienced throughput capacity constraints in a third-party transmission line in the Kaybob East area, curtailing our production by approximately 2,500 to 3,000 boe per day.

Despite this capacity constraint, during January and February 2013, the company’s production averaged approximately 7,500 boe per day, which was comprised of more than 54% liquids. Now particularly to the higher liquids rate, in late February 2013, Athabasca completed the construction of a 35-kilometer-long pipeline interconnect between the Kaybob East and Kaybob West batteries.

Unfortunately, at the same time, in end of February, Athabasca experienced additional throughput constraints due to unexpected downtime at the Keyera Simonette gas plant. Though unexpected operational issues at the Keyera gas plant were quickly resolved by Keyera, showing that they are excellent operators, and the plant was ready to resume full operations early March, however, Keyera is required to meet a certain a sulfur requirement on a average quarterly basis, as required by the ERCB license. And due to the previous operational issues, they’re unable to meet those requirements in Q1. As such, they need to defer startup until April 1; the start of the second quarter.

The Kaybob interconnect pipeline will be commissioned in conjunction with the resumption of full operations at the Kaybob plant – sorry, Keyera plant. Pipeline start-up will enable Athabasca for the first time to switch to its wholly-owned infrastructure, lessening the impact on these third-party facility constraints and bringing its currently curtailed production and additional wells on stream. Until then, Athabasca expects a production rate in the range of 4,000 boe per day to 5,000 boe per day.

Athabasca will release its reserve update next week, March 28, together with the Annual Information Form.

For 2013 outlook, in December 2012, Athabasca’s Board of Directors approved the 2013 capital budget of $798 million, and set a mid-year production guidance of 11,000 boe per day to 13,000 boe per day. Athabasca intends to conduct a mid-year review of its 2013 capital budget.

Final 2013 capital budget and year-end production guidance will be based on commodity prices, possible corporate events in addition to well performance and type curves from different areas, such as Kaybob East versus Kaybob West, and Placid/Saxon, and based on well performance and type curves between different geological formations, such as Duvernay versus Montney.

The company is evaluating operational procedures and future well allocations as well in order to best benefit from the current price differentials between condensate and light oil. For the thermal oil division, we will continue to build the Hangingstone 1 Project. Athabasca anticipates that the Dover joint venture will receive regulatory approvals in 2013 for its 250,000 barrels per day SAGD project. Receipt of regulatory approvals provide Athabasca with the opportunity to exercise the Dover put option for the price of $1.32 billion, which is all tax sheltered.

Joint venture arrangements continue to represent excellent vehicles for Athabasca to develop its 4.3 million acres net of thermal and light oil assets, tapping into third-party capital and third-party technical expertise. To that end, the company continues joint venture discussions with world-class E&P companies.

Athabasca will continue to allocate financial and human resources, in parallel and at a similar pace, to grow these complementary businesses, enabling the company to balance the high returns and flexibility inherent in the light oil business with the attractive and stable long-term returns and production characteristic of the thermal oil business.

So with that, I would just thank you for your time and attention. And we are ready to take questions.

Question-and-Answer Session

Operator

Thank you. And ladies and gentlemen, we will now conduct the analyst question-and-answer session. (Operator Instructions) Your first question comes from the line of Peter Ogden, Bank of America. Your line is open.

Peter Ogden – Bank of America

Morning. Couple of questions on the Dover regulatory approval; could you maybe just walkthrough what specific steps remain, and what you’re waiting for, and maybe the timeline for any kind of hearings going forward? And where we’re at with – on that, please?

Sveinung Svarte

Yeah. Hi, Peter. I can do that. Well, for first, we don’t know exactly the full reasons for the statement of concerns which have been filed. We won’t know that before that group has done its filing next week. But we are in constant dialogue with the other party, and concerning the project, keep a good relationship. And depending on the outcomes on those dialogues, a public hearing maybe held late April.

As you know, hearings are formal parts of the excellent regulatory system in Alberta. And if it takes a hearing to achieve regulatory approvals, we will go through that hearing. This is nothing new, and something most large oil sands projects have gone through before. And if such a hearing takes place, it would be end of April so it’s finished early May. And then, ERCB has 90 days to – before they have to come up with their ruling. So we will probably then get ERCB approval late July to early August.

Peter Ogden – Bank of America

And if an agreement comes into place before the hearing, then the ERCB can rule almost immediately? Or is there a timeline for that as well?

Bryan Gould

Hi, Peter. It’s Bryan Gould here. Good morning. So concretely, Peter, the next step is there’s a deadline of March 25, and parties have to file, what’s termed an intervention, at that point. And essentially it’s a filing with the details behind their concerns. At that point, Athabasca has two weeks to essentially respond to the ERCB, assuming that issues are either deemed to not have standing or not be warranted, or we deal with them in the meantime, that could eliminate the need for a hearing.

Peter Ogden – Bank of America

Perfect. My last question may be a bit obscure, but in the last year, you had – you said you were undergoing some tax-related reviews. This year, you’re a little bit more specific in it – specifically around the transaction with PetroChina and the March 2010 capital dividend. Can you maybe explain that a little bit further and what the CRA is looking at? And what the possible magnitude of that outcome might be or?

Sveinung Svarte

I can do that, Peter. For us, Athabasca, we have not been reassessed and we have not received anything saying that we will be reassessed. So these are at preliminary stage, and it’s too premature to project any quantity of potential outcome at this stage.

Peter Ogden – Bank of America

Is anything new in 2012 that, like I said, it was mentioned in 2011 was another review initiated in 2012 or was it.

Sveinung Svarte

No, no. Nothing.

Peter Ogden – Bank of America

Same.

Sveinung Svarte

Nothing new.

Peter Ogden – Bank of America

I see. Okay. Thanks very much. That’s all from me.

Operator

Your next question comes from Matt Taylor with National Bank. Please go ahead.

Matt Taylor – National Bank

It’s just on that CRA tax reassessment. What could the potential liability be? You guys probably have kind of assessed that. Can you provide any color to that?

Sveinung Svarte

As I say we haven’t received any sign of reassessment saying we’ll be reassessed. So at this time it’s preliminary. And it’s too early and premature to project any quantity on potential outcomes.

Matt Taylor – National Bank

Okay and maybe a second question. What has been the average cost to date on the Montney wells and also recent wells? And what are you budgeting going forward for the program?

Bryan Gould

Hey, Matt. It’s Bryan Gould again. So the cost of the Montney wells, they vary a little bit depending on whether we’re at sort of in the east side or the west side of our land position. But in general we’ve brought them now down, drill complete and tie-in to about $4.5 million. Really pleased that we’re seeing cost improvements on both the drilling and completion side. We expect that there’s further room to go there as we truly move towards pad drilling.

And there are a number of very concrete cost saving opportunities as we move more into a manufacturing sense. We have deliberately increased the size of our frac treatments in some of the wells. And so in my view, those are big costs. And we’re going now in some wells from 30-ton treatments to 80 tons, and that costs another couple of hundred thousand dollars. But in general, I’d say, answer to your question is in around $4.5 million.

Matt Taylor – National Bank

Great. Thanks, Bryan.

Bryan Gould

Okay.

Operator

Your next question comes from Mike Dunn with FirstEnergy. Please go ahead.

Mike Dunn – FirstEnergy

Good morning, everyone. Just one your Montney well inventory, you talked about your year-end inventory. Can you just provide us an update with how many wells are awaiting tie-in currently that we might, I guess, expect on in the second quarter? Thanks.

Bryan Gould

Yeah, Mike, it’s Bryan here. We have 45 producing wells. To Sveinung’s earlier point, we’ve to-date not actually ever had all of them on in production, but expect with the completion of the interconnect and once all the third-party processing is back up and running, we should be able to get that all on stream.

This year, we’ve rig released 15 wells. We have completed 10. And at the current moment, we have eight wells either undergoing or awaiting frac treatment. We have two frac spreads going right now. It is spring break-up, but I’m optimistic that even despite that, we should get, I would say, at least half of those done through break-up. So not a big inventory of wells still awaiting completion, and we’ll work our way through that during the break-up period.

Mike Dunn – FirstEnergy

Okay, great. And can you just remind me how many wells you had producing when you were at 10,700 boe per day there in mid-December?

Bryan Gould

I think it was 23 wells. And not all – some of those were choked back.

Mike Dunn – FirstEnergy

Sure.

Bryan Gould

We have notably held back the 2-34 Duvernay wells we’ve discussed previously to safeguard the long term. But other wells are also constrained to a degree because we were having to manage our gas throughput through third-party facilities; so there’s more capacity as we get to ramp-up here, beginning of April.

Mike Dunn – FirstEnergy

Sure. And then.

Andre De Leebeeck

Mike, just – Andre here. It’s 33 wells. Everything else remains as explained.

Bryan Gould

Sorry about that.

Mike Dunn – FirstEnergy

33; not 23?

Bryan Gould

Yeah. That’s my dyslexia. Apologies.

Mike Dunn – FirstEnergy

Sure. And on that Duvernay well, guys, any guidance on what that might be producing if it wasn’t held back?

Bryan Gould

No. Quite a bit more. The pressure’s hanging in very nicely at above 20 mPag. Yeah, we have a sense of that, but that’s not the right way to produce the well, but it – we have seen basically no decline yet.

Sveinung Svarte

Mike, I have the same question. I’m asking him to open up a well every day, but.

Mike Dunn – FirstEnergy

Okay, guys. And on year-end reserves, any comment qualitatively on any – on what we should expect presumably in the next couple of weeks here?

Bryan Gould

It’s coming out next week, Mike. We’re just finishing up the AIF. As you know, we have two evaluators. And so there’s some extra steps for us to get it all consolidated together. So.

Mike Dunn – FirstEnergy

Sure.

Bryan Gould

Too early to comment. But you’ll see it next week.

Mike Dunn – FirstEnergy

Okay, thanks.

Operator

Your next question comes from Roger Serin with TD Securities. Please go ahead.

Roger Serin – TD Securities

Thank you. Good morning, everybody. A couple of questions for you, do you have a throughput obligation with Keyera?

Bryan Gould

We have a firm P1 capacity at the Keyera plant. Yes, and there is an obligation there.

Roger Serin – TD Securities

Bryan, would you care to indicate whether it ramps up? What its volumes are? And any more details?

Bryan Gould

No. Not at this stage, Roger.

Roger Serin – TD Securities

Of course not. Okay. Moving on, I’m trying to, obviously, like some of the other callers, looking at the light oil. And most of the data is not the – certainly, the producing hours aren’t public. Can you give me a sense to; you were talking about the number of wells on when you were producing 10,700 boe per day, 33 wells. But how much of the production was, say, from the top one well, the top five, the top 10? Something to give us a sense of distribution.

Bryan Gould

Roger, that’s a great question. I have to get back to you on that. I mean clearly, as we’d expect, there’s a statistical spread in these wells. Quite frankly, some – many of our best wells are in Kaybob East, and have not even been on production yet, given the infrastructure timing. So it’s a little bit early to comment on that.

I think as we’ve also talked in the past, the wells do have extremely high liquid content, and we’re working hard on the artificial lift side of the equation installing quite a number of ESPs. We’re also working with gas lift. And so it’s a little bit early to comment on the real potential of the wells because we have to unload the liquid in the well bores to really, really see what sort of longer-term production capacity is.

Roger Serin – TD Securities

Okay. I’ll come at this a little bit differently then. I won’t give up just yet. So knowing what you know about well costs in the $4.5 million to $5 million range, what would you say you need in terms of breakeven EURs and say, liquid split for – and I’ll focus more on the Montney than the Nordegg for the Montney to work, ignoring your infrastructure which is already sunk cost?

Bryan Gould

I’d say that the type curves that we sort of published earlier, which were based on our screening economics, were more than sufficient at these well costs to generate healthy returns. It’s a little bit complicated, Roger, because we see differences in gas liquid content, also across the spread. So I don’t want to be – I don’t want to get too specific here, because there’s a difference in, you’ll say, drilling wells in Kaybob West, where we see higher gas content versus, say, Saxon or Kaybob East, where it’s either more crude oil or more condensate. So it does depend a little bit.

Sveinung Svarte

Obviously why we have designed the budget this year to basically have the first half of the year to watch type curves through the different areas, watch type curves from formation to formation and judge exactly what the different type curves are in the areas, and develop our final development plan for that.

Bryan Gould

We do watch the net-backs in each area. And there’s further optimization opportunities on those, Roger. So for example, we’ve talked about putting in, essentially the ability to split-out or condensate and capture that price uplift, and that will make quite a difference in the net-backs. And we’ll skew our drilling program towards that later on in the year.

Roger Serin – TD Securities

Okay, that makes sense. The – I guess the one other question; so with your budget the way it is, if you were to do some more work in the Dover West carbonates, would your budget increase or would you just be reallocating capital do you think?

Bryan Gould

So to take – the pilot that Sveinung discussed in his comments is not currently in the budget. So that would be an increase.

Roger Serin – TD Securities

Okay. Got you.

Sveinung Svarte

But we won’t really be spending a lot of money on that this year, with next year at the earliest.

Bryan Gould

Exactly.

Roger Serin – TD Securities

Okay. Thanks very much, guys.

Operator

Your next question comes from Andrew Potter with CIBC. Please go ahead.

Andrew Potter – CIBC

Thanks. Most of my questions have been answered, but just kind of building on the questions about the Montney. I think what you said when you initially started the Montney program that you’re kind of looking for IPs in the 300 boe-a-day range. So just – I know there’s still a lot of noise in that data, but I guess just on average, are you still feeling pretty comfortable with those 300 boe-a-day IPs?

And then, just two questions on the Duvernay. I mean, you’ve talked a lot about the 2-34 well, which is a very good well, but maybe if you can give a little bit more color on the 6-10 and 8-18 well? I mean, the 6-10 well on public data anyways, looks like it was a good well in January. Maybe you can give us a bit more color on that?

Bryan Gould

So the answer to your first question is just yes, we’re still comfortable with that sort of IP range. I think we’ve described in the past, Andrew that we think we’ve learned some things on the frac treatments in the Duvernay. And so the third well, 2-34, we definitely did some things different there. The 6-10 well is a good well. I’m pretty keen to go back into that early and apply some of our new learnings on frac treatments. Our team has a very strong feeling that we can make that area work even better with what we’ve learned on stimulations.

Andrew Potter – CIBC

And what about the 8-18 well? That’s your first Duvernay oil well, right? Or is that.

Bryan Gould

Yeah. So I think the same learnings will apply on the stimulations there. And it’s part of that Kaybob East area that we just haven’t been able to fully open everything up on a consistent basis, because of the gas handling constraints in the third-party. So we’re really looking forward to April 1, when we can finally just turn everything on full.

Andrew Potter – CIBC

Right.

Sveinung Svarte

The last flow in that well was around 800 boe per day as well, and above 85% oil basically. And – but then we had to shut it in because of these third-party constraints. So we are going to back – get back on it here.

Andrew Potter – CIBC

Great, okay. So that’s what I was looking for. Is there an update on February production from that 800 boe-a-day? But it doesn’t sound like there is anything new to say there to the shut-in, is that right?

Bryan Gould

That’s correct. That’s fair.

Andrew Potter – CIBC

Okay. Thanks.

Operator

(Operator Instructions) Your next question comes from Eugene Vath with Scotiabank. Please go ahead.

Eugene Vath – Scotiabank

Yes. Just quickly on the Duvernay 2-34 well. Wondering if you guys can give us a sense of how much of the liquids content is condensate.

Bryan Gould

All of that.

Eugene Vath – Scotiabank

Okay. Very well.

Bryan Gould

It’s all condensate.

Sveinung Svarte

Now, the liquid content we talk about is basically free condensate.

Eugene Vath – Scotiabank

Okay. Thanks, guys.

Operator

And this concludes the analyst Q&A portion of today’s call. We will now take questions from members of the media. (Operator Instructions)

And Mr. De Leebeeck, there are no further questions at this time. Please continue.

Andre De Leebeeck

Okay. Thank you. 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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