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Executives

Andre De Leebeeck - VP, Investor Relations and External Communications

Sveinung Svarte - President and CEO

Rob Broen - COO

Kim Anderson - CFO

Analysts

Mark Friesen - RBC Capital Markets

Joshua Gale - GMP Securities

Menno Hulshof - TD Securities

Athabasca Oil Corporation (OTCPK:ATHOF) Q1 2014 Earnings Conference Call May 8, 2014 9:30 AM ET

Operator

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Athabasca Oil Corporation's 2014 First Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions) 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, Corporate Projects. Please go ahead Mr. De Leebeeck.

Andre De Leebeeck

Thank you, operator, and welcome everyone to our 2014 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 those advisories.

Sveinung Svarte, Athabasca's President and Chief Executive Officer, will begin the call discussing the progress made in the first quarter. Rob Broen, Athabasca's Chief Operating Officer, will provide a summary of operations, followed by Kim Anderson, Athabasca's Chief Financial Officer, who will present a summary of the first quarter financials. Please proceed, Sveinung.

Sveinung Svarte

Thank you, Andre. Good morning, everyone. The first five months of 2014 have been very productive for Athabasca. Earlier this year, we stated that an important goal was to continue the transformation of Athabasca into a producing company focused on capital discipline and strong operational performance. We remain committed to this transformation, and as we have communicated, we are focusing on operational and capital activities on Dover elimination and on completion of our Hangingstone Phase 1 thermal project.

Highlights from last quarter include, Light Oil production averaged approximately 6,300 barrels of oil equivalent per day with 47% liquids, in line with our stated guidance. We also obtained results from two more Duvernay wells. One of the wells was brought on-stream near the end of first quarter with an average production of approximately 750 boe per day in the first 30 days and with a free condensate yield of as much as 475 barrels per mmcf. A second Duvernay well was tested over an extended four day period with an average rate of approximately 1,400 boe per day with a free condensate yield of 284 barrels per mmcf during the final 24 hours of the test. Both wells flowed at restricted rates. Needless to say, I'm very pleased with these results.

In Thermal Oil, we made significant progress on the development of the Hangingstone Project 1. Infrastructure and facilities construction continued and all 25 producer laterals and 25 injected laterals have now been drilled. The project was 80% complete as of March 31 this year, with first steam targeted towards the end of the first quarter next year 2015.

We also remain strongly committed to building a stronger balance sheet and enhancing our liquidity position. I'm very pleased that we have now received Alberta Environment's approval of the Dover Commercial Project, and more importantly, exercised our put option to sell our remaining 40% interest of the Dover Project.

In addition, we have just completed the refinancing of our existing credit facility, replacing it with approximately $425 million of committed term loan and revolving credit facilities with terms that are much better suited to Athabasca's longer-term development programs. Athabasca is fortunate to have excellent assets and with the recent credit facility refinancing and anticipated receipt of the Dover proceeds, which we expect this summer, we should be well-positioned for profitable growth going forward.

With that, I will hand the call over to Rob Broen who will present the first quarter operational highlights. So, Rob, please go ahead.

Rob Broen

Thank you, Sveinung, and good morning everyone. I'm pleased this morning to provide an update on operations for both Light Oil and Thermal Oil divisions. As Sveinung mentioned, our Light Oil production averaged 6,299 boe per day with 47% liquids in the first quarter, a 5% increase compared to 6,024 in the first quarter of 2013. This production is in line with our guidance that we previously stated of 6,000 to 6,500 boe per day.

The objective of our capital program over the last four quarters has really been to maintain our base production, which is primarily Montney, while shifting our focus towards the future growth of the Duvernay. Our production guidance for the second quarter of 2014 remains unchanged at 5,500 to 6,000 boe per day and that includes the Keyera's Simonette plant shutdown, a plant shutdown that occurred in April of 2014. That turnaround was successfully completed in the last 10 days of April and production started back up again on April 30. We now have our full production back on-stream.

The Company also recognized a netback of $36.95 per boe in the first quarter of 2014 compared to $33.27 per boe in the first quarter of 2013. This increase is primarily due to commodity prices.

I'm now going to move to an update on the Duvernay operational results. As we have said previously, we continue to focus our Duvernay drilling program with a goal of delineating and maintaining the high-graded land position in the Kaybob region. During the quarter, we drilled two and successfully completed four horizontal Duvernay wells. The four Duvernay horizontal wells were completed using multi-stage fracturing techniques. We've been using a hybrid frac design and that uses slick water followed by a gelled liquid in the final stages to ensure we place optimal sand concentrations. The lateral length of our wells has averaged approximately 1,400 meters and we have an average of 16 to 18 stages per well. I should clarify that each stage has four limited entry perf clusters and that results in up to 72 stimulation intervals, and our belief is that maximizes stimulated rock volume.

Our objective has been to pump at very high rates, in excess of 15 cubic meters per minute while pumping these fracs, and as our casing design, we run a larger casing and it's allowed us to do that. These techniques have been more successfully employed in our 2-34 well, which remains one of the best wells in the basin, and the technique is also common to other shale plays in North America. I'm pleased that with this frac design, we successfully placed all stages in each well during 2014.

So now on to the results. One of the Duvernay wells, as Sveinung mentioned, is at Kaybob West and the location is 1-7-64-20W5. That was brought on-stream near the end of the first quarter. Average production for this well in the first 30 days was approximately 750 boe per day. That's 1.2 million a day of gas and 560 barrels per day of condensate, with a free condensate yield of 475 barrels per million. That well has been flowing at a restricted rate and the flowing pressure at the end of the 30-day period was 2,300 PSI.

Second well in the Simonette area at 1-25-62-25W5 was tested over an extended four-day period after initial cleanup. During the final 24 hours of the test period, this well was flowing at an average rate of 1,400 boe per day. That's 880 barrels a day of condensate, 3.1 million a day of gas, with a free condensate yield of 284 barrels per million. This well was flowing at a highly restricted rate and its flowing pressure was approximately 5,400 PSI at the end of the test period.

So, our preference really is to establish 30-day IPs instead of reporting test rates. So, we are pleased with these preliminary results and we really look forward to seeing this well in production. This well had a very high reservoir pressure, it was almost 11,000 PSI, requiring us to upgrade our well-side equipment designed to handle the higher pressures. Obviously dealing with a high pressure is a good problem to have and this well is expected on-stream mid-May through a third-party facility, and in fact that well will be on-stream in the next couple of days.

The remaining two wells are located in the Kaybob West area and they are in section 29-64-20. It was two wells on a single pad and these wells were deliberately put on a three-month soak perio0d. So observations from some other North American shale plays and early results from the Duvernay show significant improvements in deliverability and pressures with the soak period, and we have several data points so far and our goal here is to establish a relationship between soak time and initial well results. So we will clean these wells up and test them once the soak period is done and we expect the wells to come on-stream in July.

These two wells, I should mention, were also drilled – I did mention, they were drilled on a pad location, but we recorded micro-seismic data while stimulating these wells. This data is going to aid us in further optimizing our completion designs as well as understanding ideal horizontal well orientation. We remain focused on proving the resource extent first and understanding the best parts of this basin.

So now in total, Athabasca has drilled eight horizontal Duvernay wells, with four wells, soon to be five, currently on production. Clearly we are seeing an increasing amount of industry results defined by actual production, with a substantial amount of these results flowing through our Athabasca facilities. Athabasca has a large land position across all areas of the thermal maturity windows. We're seeing now higher rates in the deeper and higher-pressure areas near Simonette. We're also seeing strong rates with very significant liquid yields in the shallower and less expensive areas of the basin near Kaybob.

It's still early and we recognize that results do vary across the basin, but all of these areas have the potential for significant profitable growth for the Company. And I should mention also that a new liquids yield map, actually based on well production results, can be found on our Web-site in our latest investor presentation this morning.

As far as costs go, our costs have ranged between $15 million and $19 million to drill and complete the last four wells, and these are on single well pads. This includes considerable money spent to vertically drill the wells, core them and then plug them back for horizontal drill. So these costs are in line with our expectations for this stage of development and we see opportunities for significant reductions in cost, particularly as the play moves towards pad drilling.

Finally, I should mention that the drilling of these wells has continued a large portion of our 2014 land expiries. Our land is now approximately 60% held in our high-graded areas. We anticipate that drilling a maximum of six additional wells beyond Athabasca's current 2014 capital budget will allow us to hold 95% of our high-graded 200,000 net acres into the intermediate term. Expiries are in really good shape and we have the ability to control our pace on these lands in the future. We've also been working hard with some industry partners to consolidate positions and minimizing the number of landhold wells required. The objective here will be to allow us and others to add production-adding locations.

On the infrastructure side of the Light Oil business, in the first quarter of 2014, when we talked about this before, but we initiated the installation of a 10-inch pipeline that connects our Kaybob West facility to SemCAMS' KA Gas Plant, and that was done as part of the Q4 2013 sale of the 50% interest in our Kaybob infrastructure. We expect construction of this pipeline to be complete during the second quarter of 2014, and in fact we're almost ready to commission that pipeline.

We retained a 10% working interest in this pipeline and it was at no cost to Athabasca. This transaction continues to progress our strategy of creating future optionality and scalability for egress of our production in this area. Athabasca is well-positioned for future growth.

I'm now going to move on to the Thermal Oil side of the business. So in Thermal Oil, we made significant progress across the entire Hangingstone project, including infrastructure and facilities construction as well as the drilling of our SAGD wells. All piping and equipment modules have been delivered and set at the Central Plant. The fuel gas and source water pipelines have also been completed. We expect peak activity on site during this summer in 2014 as we progress the mechanical installation as the central processing facility.

On the drilling side, all 25 laterals and all 25 injection laterals have now been finished. The two rig program has delivered better-than-expected cost and schedule performance and the reservoir quality is consistent with expected results derived from our extensive appraisal drilling and reservoir modeling. We are estimating 91% effective wellbore length in the 25 well program compared to an initial planned effective wellbore length of 89%. 20 producer lateral pairs have been completed now in terms of completion operations and we are finishing those completion operations on the last well pad. We expect this operation will be finished before the end of the second quarter, really within the next month.

The overall project at Hangingstone is 80% complete on a cost basis as of March 31, 2014, with approximately 90% of total Hangingstone Project 1 cost already contracted. Construction of Hangingstone Project 1 is anticipated to be complete around the year end of this year 2014 with first steam targeted towards the end of the first quarter of 2015. First production is expected approximately six months after first steam and production plateau will occur in 2016. That's consistent with what we stated previously.

During the first quarter of 2014, design for the Enbridge dilbit pipeline continued and field work actually commenced with the clearing of the pipeline right away. This pipeline will connect the Hangingstone Central Plant to the existing Enbridge Cheecham Terminal and is expected to be in service in the latter half of 2015, and that aligns with the ramp-up of production from Hangingstone Project 1. This pipeline is being designed to have sufficient capacity to handle the anticipated additional production from Hangingstone expansion.

Finally, I want to mention, we are currently 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, followed by a 32,000 barrel a day expansion, which is a total of 40,000 barrels a day in the expansion. Our goal here is to provide optionality for growth, depending on different funding scenarios. Our intent is to progress both these options through engineering design specification phases and that will allow us to make investment decisions at a later date.

So that concludes my operations update, and I would now like to turn the call over to Kim Anderson for a financial update.

Kim Anderson

Thanks, Rob, and good morning everyone. As Sveinung mentioned, I will provide a brief summary of Athabasca's financial results followed by an update on our liquidity position and our updated 2014 capital budget.

Sales for the first quarter of 2014, which are 100% attributable to the Light Oil division including petroleum and natural gas sales and third-party midstream revenues, were $35.4 million, an increase of 26% over the prior year quarter. This increase was due to higher production volumes and realized prices, as Rob spoke about earlier. Higher revenues were partially offset by higher first quarter operating expenses, which increased by 10% to $9.5 million over the prior year due to higher production volume.

Royalties also increased by $3.6 million to $5 million as some of Athabasca's producing wells drilled in prior years have now come off low initial incentive royalty rates. Net loss and comprehensive loss for the quarter was $21.3 million compared to $25.5 million in the prior year, with higher Light Oil production in netbacks as well as lower G&A, stock-based compensation expenses, and financing and interest charges, offsetting higher depreciation and depletion expense and lower interest income.

In terms of capital, in the first quarter of 2014, capital expenditures totaled $241 million, including approximately $12 million of capitalized G&A expenses. Expenditures were comprised of $77 million for Light Oil, $158 million for operated Thermal Oil assets, $4 million for Athabasca's 40% interest in the Dover asset, and a small amount for corporate expenditures.

Turning to our liquidity position, as Sveinung mentioned, Athabasca has been strongly focused on building financial strength and continued capital discipline. As of March 31, Athabasca's liquidity position was approximately $500 million, including cash and cash equivalents, short-term investments and funds available under our previous credit facility. Recently, we have also taken steps which we believe will further enhance our liquidity position going forward.

As previously mentioned, in April we received regulatory approval for the Dover Commercial Project and exercised our put option to sell our remaining 40% interest in our Dover investment. Net proceeds of approximately $1.23 billion are expected late in the second quarter. We have also just recompleted the refinancing of our existing $350 million credit facility, replacing that facility with $425 million of committed term loan and revolving credit facility, all of which contain longer terms to maturity and much more flexible covenant structures. Combined, these two sources of funding put Athabasca in an excellent shape to support an expanded capital program in the second half of the year.

Given additional clarity on funding, Athabasca's Board of Directors has approved a modest $29 million increase to its base capital budget of $480 million. This increase is allocated as follows. For Light Oil, an increase of $15 million, which will primarily be directed towards long lead equipment and drilling commitments required in the second quarter to support and extend the Duvernay drilling program in the second half of the year. The Light Oil budget now stands at $121 million.

For Thermal Oil, an increase of approximately $6 million which will be directed towards advancing preliminary engineering work for future Hangingstone expansion. The Thermal Oil budget now stands at $354 million. And lastly for corporate, an increase of $8 million for leasehold improvements and other capital costs associated with our upcoming office move, which will be largely completed late in 2014. The total corporate budget now stands at $14 million.

Athabasca's revised capital budget also includes $20 million for our Dover joint venture which remains unchanged. The Company's total 2014 capital budget is now $509 million, excluding capitalized cash general and administrative expenses which we expect to be approximately $50 million in 2014. Athabasca expects to provide an updated capital budget early in the third quarter, following receipt of the Dover put option proceeds, further correction information from our new Duvernay wells and confirmation of our Duvernay development strategy.

We will also continue to evaluate additional funding sources, including joint ventures, to advance the development of our portfolio of Light Oil and Thermal Oil opportunities. We remain committed to a disciplined approach to growth and will only allocate financial resources and personnel to projects that are fully funded.

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

Sveinung Svarte

Thank you, Kim. As we continue to move forward, we are focused on delivering our priorities, which are, the completion of Hangingstone Project 1, preparation for Hangingstone expansion, and the targeted Duvernay drilling and completion program. We are also committed to a disciplined approach to capital expenditures, as we highlighted several times during this call. We look forward to the receipt of proceeds from the sale of our Dover investments. I'm also pleased that we have established new credit facilities which better match our asset development [plan] (ph). With this, we are well-positioned for profitable growth in the future.

We are currently reviewing all of our capital opportunities and we strive to finalize our business strategy early in the third quarter. As part of the process, we are evaluating development strategies to maximize the value of our Duvernay assets. We are also evaluating future development opportunities within our Thermal Oil division, such as the potential Hangingstone debottleneck, which can drive additional cash flow to Athabasca on a self-funded basis. We will be prepared to discuss our full go-forward strategy more fully when this review is over early Q3.

I'd like to thank all of Athabasca's team members for their continued hard work. We have a tremendous asset base that we now believe is well-positioned for future. Finally, I would like to particularly thank Andre De Leebeeck for having piloted these calls for us for last two years. Andre will now assume a new role as Vice President, Corporate Projects. The investment relations and communication functions will be assumed by Matthew Taylor, who many of you know from his previous role as energy financial analyst, most recently with National Bank. Matthew joined us this week as Vice President, Capital Markets.

So with that, we are 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) Your first question comes from Mark Friesen from RBC Capital Markets. Please go ahead.

Mark Friesen - RBC Capital Markets

Just a few questions around the table there. First of all, Kim, could you mention what the primary covenants are on the new credit facility?

Kim Anderson

Sure. I think the main difference for the new credit facility is we moved away from earnings-based covenants to asset coverage covenants. So we've got some approved reserve covenants and then we've got a total asset-to-debt covenant as well.

Mark Friesen - RBC Capital Markets

Okay thanks. And also, what is the remaining CapEx profile for spending at Hangingstone for the next few quarters?

Kim Anderson

Next few quarters, we would be – just stay with me here.

Mark Friesen - RBC Capital Markets

We can come back to that if you want, Kim.

Kim Anderson

I think it's about $200 million for the rest of the year.

Mark Friesen - RBC Capital Markets

Okay, and fairly evenly split across the quarters?

Kim Anderson

Yes.

Mark Friesen - RBC Capital Markets

Okay, thank you. Rob, just to clarify a comment that you made in your prepared comments there, you mentioned first production at Hangingstone coming about six months after first steam, is that correct?

Rob Broen

Yes, so Mark, we have our first steam targeted towards the end of the first quarter 2015 and then we have a ramp-up profile, and production starts to come in the first quarter, six months after your first steam, and so that's why I stated that.

Mark Friesen - RBC Capital Markets

Okay. Just changing gears then to the Light Oil division, any thoughts of increasing your lateral length on the Duvernay well?

Rob Broen

Yes, that's good question, Mark, and actually we do believe that longer horizontal wells in this basin are going to work and be capital efficient, but for now our objective is to prove the productivity and control costs at the same time. So we've had good success with the 1,400 meter lateral length at our first wells, that's what we've decide to do, we've effectively stimulated them, and I think future steps are going to be longer horizontal laterals for us.

Mark Friesen - RBC Capital Markets

What kind of length do you think you can get out there?

Rob Broen

I do know that others in the basin are drilling well over 2,000 meters now. So I certainly think that's capable for us. And I think the bigger question is, how are we going to effectively stimulate a longer horizontal length without the cost being too extreme? And so we have some plans going forward on that.

Mark Friesen - RBC Capital Markets

Okay, thank you. On the 1-7 well, that well is moving towards more the northern leases there where a lot of your lands are. It's got a higher condensate rate but lower gas rates overall. Is that something you find predictive of the northern leases, and if it is a lower gas rate, how do you think that impacts the longer-term productivity?

Rob Broen

So if you go on our IR pack this morning, you'll see our new liquids yield map, and that's actually based on production data that we've seen in the area. So certainly liquid yields increase as you go further north, and we've seen that on our 1-7 well. We're pretty pleased with the results we've seen on 1-7. The liquids that we're seeing there is a 47 degree API condensate. The well is flowing, it's still flowing at restricted rates. So there's wells that are well into the high liquid yield portion of the reservoir now and they are giving good results.

And I think if you look in analogues, if you look down at the Eagle Ford, they've been drilling in oil window there for a long time now with good rates and good recoveries and in fact down-spacing. And I should remind you that as you get further north, it's shallower, so it's cheaper to drill, and the fact still remains that even in these areas it's over-pressured and pressure works to your advantage. So we're pretty pleased with the results we're seeing so far.

Mark Friesen - RBC Capital Markets

Okay, so then the gas trade overall is not an issue just because the depth of the reservoir decreases but the pressure stays high, is that what you're saying?

Rob Broen

Well, pressure is relative to depth, but relative to a normally pressured reservoir, this reservoir is over-pressured, and that pressure helps you get the oil out of the shale reservoir. So, I mean time is going to tell. We are drilling further north, other operators are as well, and as you know, we have a significant land position further north, we're well on our way to holding that land position and we can control our pace at a measured level.

But I would mention, I mean if you look across the basin, we have a pretty significant land position. And so, if you go over to Simonette, we have a significant land position there, we have a very significant land position at Kaybob West, and then we have land further east that is not as well tested so far. So, we have the ability to control the pace that we drill across this basin, and we have the ability to focus in the areas that are getting derisked and add production fairly quickly, and we have the ability to prove up more liquid, higher liquid yields in the north of basin at a measured pace, and that's our approach here.

Mark Friesen - RBC Capital Markets

Okay, thanks, Rob. And just a final question for Sveinung. In your comments, you didn't make any particular mention of Duvernay JV as still being one of your sort of critical strategy items in the near-term. Can you maybe just give an update on where the Duvernay JV is at and things, specific milestones we should be looking forward to on that?

Sveinung Svarte

We've been careful about giving exact timelines because I've been doing that before and it didn't work out, a couple of years ago. But we are continuing to evaluate our strategies to maximize the value of the Duvernay, and as you've seen, the more we work on this, we believe that the Duvernay play continues to get more valuable. At any time it's supported by industry results and activity levels. You have seen our latest results which are very good. We also saw another producer releasing a good well today, and that well is just located next to our land. So the industry is derisking this play together. And as you know, the land tenure in Alberta is very good, so it's not a problem to retain these lands. We can drill another six wells and retain 95% of the high-graded Duvernay.

But to your question, our final development plan could surely involve a partner in all this area or parts of it, but we will not decide on that before – and to what extent, before we have the put call money in the bank and also seeing the value and results from these two wells that Rob put on soak in the Kaybob West area later in July as we put them back on. So that's probably when we could come up with a final strategy on Duvernay. But the data room is going on and the interest in the play is very large.

Mark Friesen - RBC Capital Markets

Okay, so over the past year, there's been a lot of discussion of the Duvernay JV very specifically. Now it sounds like the language may be looking at other options. Is that fair to say, that a JV may not necessarily be the way you want to pursue this?

Sveinung Svarte

I think for us the goal is to take a JV on all the assets we have and on Duvernay that's surely our goal as well. But we always said that we need to see three things. First, we need to know the full interest from the industry to join us, which we will do probably around mid-year this time as well, and more importantly, we need to get the put call in the bank, and also see the results of these wells, because those are the three things we really need to make up our final strategy on what to do to development in Duvernay.

Mark Friesen - RBC Capital Markets

Okay. So when are bids due then on the JV process?

Sveinung Svarte

We don't have any final bid deadlines. It continues as ongoing process and [indiscernible] fully works.

Mark Friesen - RBC Capital Markets

Okay, thanks very much.

Operator

(Operator Instructions) Your next question comes from Joshua Gale from GMP Securities. Please go ahead.

Joshua Gale - GMP Securities

Just curious on the first lien deal, why would you price a deal at 8.25% all-in when your 7.5% second lien bonds are trading above par in the secondary market?

Kim Anderson

Sure. Kim Anderson here. I think really in my mind, the deal that we structured is a reflection of the current market tone, and I think it's not a direct comparison to what we're trading at right now. Two of the things that I look at that are pretty important in terms of us assessing this deal is; one, the tenure, so we have extended the tenure on our debt for a five-year term; and then again in terms of flexibility, the covenant structure in the refinancing provisions that are part of this deal are more flexible than we have under the high-yield notes.

Joshua Gale - GMP Securities

Okay, thank you.

Operator

Your next question comes from Menno Hulshof from TD Securities. Please go ahead.

Menno Hulshof - TD Securities

Just a follow-up on Mark's questions. What pad and well design have you modelled into your $10 million to $15 million per well long-term target? And I understand that that's all influx, but any thoughts in that regard would be appreciated.

Rob Broen

So our long-term field development plan right now assumes four wells per section, and our view is in thicker parts of the play it might be six or eight wells per section, and you see that in other shale plays, but our assumption right now is four wells per section. And from a surface standpoint, we could put anywhere from six to eight wells on a pad. And in fact, if you look at other shale plays, it is pretty well documented, the learning curve on costs that happened in shale plays, and I have experience in the Marcellus and the Eagle Ford and have seen that, and when you get on a pad location and share the cost of multiple wells, and you zip or frac the wells, the costs come down significantly, and that's the future for this play.

Menno Hulshof - TD Securities

Okay thanks. And then moving on to Hangingstone construction, what items are on the critical path right now and are there any that really concern you from a timing perspective?

Rob Broen

I mean right now we are over 90% contracted with services. All the modules are on site. We're currently – while we started here very recently with the mechanical installation basically connecting all the modules on site, on the pads we're just about done our completion operations, construction is happening on the pads. So, frankly, we feel pretty good about the schedule that we've put out. And so, I really can't say there's anything that's giving us a lot of concern right now.

Operator

(Operator Instructions) This concludes the analyst Q&A portion of today's call. We will now take questions of the media. (Operator Instructions) Mr. De Leebeeck, there are no further questions at this time. Please continue.

Andre De Leebeeck

Thank you for joining us today. Our call is now complete.

Operator

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

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