Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Andre De Leebeeck - Vice President, Investor Relations

Sveinung Svarte - Chief Executive Officer

Brent Heagy - Chief Financial Officer

Rob Broen - SVP, Light Oil

Rick Koshman - VP, Projects and Thermal Operations

Analysts

Mark Friesen - RBC Capital Markets

Mike Dunn - FirstEnergy

Matthew Taylor - National Bank Financial

Claudia Cattaneo - National Post

Athabasca Oil Corp (OTCPK:ATHOF) 2Q 2013 Results - Earnings Call Transcript July 31, 2013 9:30 AM ET

Operator

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to Athabasca Oil Corporation's Second Quarter Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions) As a reminder, this conference call is broadcast live on the Internet and recorded.

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

Andre De Leebeeck

Thank you, operator and welcome, everyone to our 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.

Sveinung Svarte, Athabasca's President and Chief Executive Officer will begin the call, discussing the current state of the business and recent events followed by Brent Heagy, Athabasca's Chief Financial Officer, who will then present a summary of the Q2 financials. Also in the room are Rob Broen, Senior Vice President of Light Oil and Rick Koshman, Vice President, Projects and Thermal Operations. Please proceed, Sveinung.

Sveinung Svarte

Thank you, Andre and good morning to everyone. For the Athabasca's second quarter 2013 was about forward momentum. This year's second quarter for Athabasca's construction budget was 12,000 barrels a day SAGD HS Project 1 on track, with over 64% of the project cost committed.

Engineering and procurement was over 85% complete, which has us very well positioned for efficient construction ramp up in the field. We expect SAGD drilling to commence in early August on major mechanical construction to start in September.

Earlier this year, Athabasca entered into an agreement with Enbridge for transportation and terminaling of dilbit for Hangingstone Project 1. A new pipeline from Hangingstone CPS to the existing Enbridge (inaudible) terminal is anticipated to be in service in latter half of 2015. The pipeline is being designed to add sufficient capacity to handle the company's anticipated additional production.

In May, the regulatory application for Hanginstone expansion were all submitted. This expansion is a 70,000 barrel per day SAGD project and is planned in two phases of 40,000 barrels per day and 30,000 barrels per day respectively, bringing the total anticipated production of the Hangingstone asset to over 80,000 barrels per day.

Athabasca completed the third production cycle of Dover West Carbonates TAGD field test during the quarter. The TAGD field has met or exceeded all design objectives which included demonstrating ability to heat the reservoir with thermal conduction and produce bitumen by gravity drainage from the Leduc carbonate formation.

Heater reliability in the horizontal wells was excellent and the conduction heating process took place faster than anticipated due to favorable rock characteristics. Regulatory approvals for the Dover West Leduc TAGD pilot are anticipated later this year. In addition we anticipate the regulatory approvals for the Dover West Sands, 12,000 barrel a day SAGD project.

The Light Oil Division continued further development of its assets in the liquid rich Alberta deep basin. The average production for the second quarter was approximately 7,255 oil equivalent per day. In June, the average production was approximately 8,550 barrels of oil equivalent per day, comprising of 50% liquids.

Keyera Simonette gas plant experience service interruptions in March and April as previously announced and Keyera responded by initiating several plants modifications. These modifications are aimed that improving sour gas processing and liquid handling. Despite these setbacks operational runtimes have continuously improved since early May and it steadily increased our production throughout the quarter.

Keyera has scheduled a planned shutdown Simonette plant in September, which will last approximately three weeks for maintenance and completion of plant modifications, as a result of this shutdown, September production will be low and we anticipate average production for the third quarter of 2013, to be and we brought down in the range of 5700 to 6200 barrels of oil equivalent per day. 5 Montney horizontal wells were completed during the second quarter and all development wells for the winter drilling programs are now tied-in.

We have drilled and -- drilled a total of 6 4 Montney horizontal wells over the last two years including 18 rig released and 22 completed in the first half of 2013. At the end of June approximately 60 wells were on production, 53 of which are Montney producers, there are also three wells that were drilled during Q2 in one isolated sections in Kaybob that affected [west].

In addition we have seven remaining wells which will be brought on stream, as the infrastructure capacities allows. The additional wells are expected to help offset decline of current production. We drilled eight fewer wells than planned in the first half of 2013 and reallocated capital in oil's optimized well performance and complete infrastructure projects.

We continue to believe that this infrastructure is critical to getting wells on production early and establishing type curves to high grade future development programs. We now own and operate key infrastructure in the heart of the Kaybob area that will be used as we execute on the Montney and the Duvernay programs. We believe that the value of this infrastructure far exceeds its installed cost and we will continue to evaluate options for capturing its value.

For the Montney over 90% of its core land is now held into intermediate terms, the focus of our initial program have been to the delineate our extensive land base, test the productive capability of the reservoir, establish a path to improve costs and ultimately high grade our assets for future development programs.

We have established three core areas at Kaybob West, Kaybob East and Saxon. Over the cycle time to drill in these areas have improved by more than 20%, while our cost for drilling and completion have improved by approximately 35% and 25% respectively in the last year.

These areas all have different cost structures, reservoir characteristics and production profiles. We have spent considerable effort stabilizing our production, including third party infrastructure debottlenecking and application of artificial lift.

Our current focus in the Montney to continue to optimize production and clearly establish type curves for each area. There are also developments in between Montney and Duvernay developments such as pad drilling to optimize cost and common (Inaudible) landing to improve revenue or increase revenue. The progress our ability to capture these synergies for future development programs. We are confident that we are able to execute the high grade Montney development program in the compelling economics and a small drilling program for Q4 this year is being considered.

We are encouraged by the strong performance over the three Duvernay wells and by results reported by other industry operators. Currently we hold 350,000 prospective net acres of liquid rich Duvernay potential including 200,000 high-graded net acres which contain greater than 20 meters of net pay and lie in the heart of Duvernay Fairway in the Kaybob area. Our long tenure is very good only requiring 13 wells to hold about 95% of high-graded acres into the intermediary terms. We've taken steps to prepare surface locations and secure services in order to execute a drilling program beginning of fall this year that will (Inaudible) over on further delineate our core position.

The company's production potential from the Duvernay is very good and full development will require significant capital investment. Our strategy has been and continues to be joint ventures to assure our future growth, a joint venture partner with a lowest to accelerate the development well and the value realization from the Duvernay. We are therefore initiated a formal joint venture process for our Duvernay holdings and we are working closely with the financial advisors on this process. As many of you know a regulatory hearing commenced on April 23 of this year for the Dover commercial joint venture project and closing arguments represented on April 29.

The Alberta Energy Regulator AER panel formerly known as the ERCB is now considering the information provided and we expect the decision shortly. The AER's recommendation will then be submitted to Alberta provincial cabinet for approval. Consequent approvals from the AER and Alberta Environment will trigger the company's rights under the Put/Call agreement to sell its remaining 40% in the Dover project to a wholly owned subsidiary of PetroChina for $1.32 billion.

Proceeds will be anticipated in the fourth quarter of 2013. I am proud of the joined at Athabasca, Bryan [energy] which has formulated Dover OPCO team on the job that Dave is representing the merits of development at Dover during the hearing process.

So with that, I would like to turn the conference call over to Brent Heagy, our CFO, who will provide overview of Athabasca's Q2 financial results.

Brent Heagy

Thank you Sveinung and good morning everyone. The second quarter brought a 20% increase of average production from the first quarter of 2013. Our average net back also grew by 10% to $36.55 per barrel of oil equivalent. As of June 30, 2015; the company has $481 million of cash equivalents and short-term investments on hand. Athabasca also has a $200 million revolving credit facility available to us.

Athabasca continued an active capital program during the second quarter of 2013 with total capital spending of $143 million. Spending was comprised of $48 million in the Light Oil division and $92 million in the thermal division with the remainder allocated to corporate assets.

Athabasca has undertaken a thorough review of capital in order to align expenditures with funding be it from exercising the put option or from joint ventures as Sveinung had mentioned. At the present time, with our current cash balance, available credit facility and current plans of capital expenditures, we have sufficient funding in place to last into Q1 of 2014.

Additionally, we continually evaluate other funding options which could include gathering value from our infrastructure assets in the Kaybob area, ongoing work on joint ventures such as with Duvernay assets which was recently initiated as Sveinung mentioned, and also for thermal assets and a potential for additional debt.

If there was delay in receiving foot proceeds or delay in getting a joint venture done, we would not approve any further Light Oil spending and we will scale back all other thermal oil spending except for our sanctioned Hangingstone 1 Project.

So with that, I would now like to turn the call back over to Sveinung who will provide closing comments before we begin the Q&A portion of the call.

Sveinung Svarte

Thank you, Brent. So as we continue to move forward, we are focused on delivering our goals which include outstanding Dover regulatory approvals and some further joint ventures. We are excited about the potential of our Montney and Duvernay assets and I am confident in our ability in deliver the results we expect.

Obviously, the Montney and Duvernay programs are contingent corporate funding and capital allocation will be evaluated after the Dover regulatory hearing process is complete. The Montney and Duvernay programs will compete for capital. But our intent is to manage a balanced program, maximizing the synergies and benefits derived from developing the two formations to the other, while preserving our land possession.

I would like to conclude by thanking Athabasca team members and especially those involved in the long term construction of Hangingstone and submitting their expansion application. We are very proud of the solid work going into these assets. We are also pleased that increased production numbers from our Light Oil properties and the reduction in operating cost received.

Our unique successful synergies all developing diverse Light oil and thermal oil grouped together to provide the basis for sustain and profit growth. So with that we are ready to your questions. Operator, please announce the first question.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question is comes from Mark Friesen from RBC Capital Markets. Your line is open.

Mark Friesen - RBC Capital Markets

Just a few quick ones, could you maybe provide a bit of extra color on what you expect in terms of the Duvernay joint venture process in terms of maybe expect the timing and how you would like to possibly restructure the JV in terms of working interest or maybe something like that?

Brent Heagy

Mark, good morning and I can do that. Well, obviously, Duvernay the initial delineation of production risks all are very encouraging, and we believe that these opportunities could be similar to Eagle Ford with large development potential of oil and gas. We know that there are about 20-30 parties who will be interested in this opportunity. We have just opened data room and this leads to early process of laying pipelines, but I think that's ideal for us to have a partner let's say 40% obviously going to reduce the exact percentage at the end of the day.

But I know always that we will take the time necessary to select the right partner and to get the right structure on this agreement. We would be the operator. Having said that, we will also be open to more inexperienced operator coming in and maybe operating in parts of the area which is also an elegant model it leads to acceleration all of development if that the case, but the base stays at the other operator unless say we keep around 60% for the participation interest.

Mark Friesen - RBC Capital Markets

Okay, great. That's very good color. Further to the comments in the release on TAGD could you provide some information maybe in terms of the length of the heat and the production cycles and maybe some of the rates that you thought?

Brent Heagy

When it comes to length, probably I have to get back to you on that but this test was basically designed to show that it could mobilize the specimen. We have done three phases and as you know that there are two heater wells, but a lower one is the producer. So the first cycle they heated and asked to show that they can mobilize the oil around the well bores and produced from the lower one.

We have pump limitation about 150 barrels per day here to withhold production rates up to that, obviously you won't get above the pump capacity and remember as all these are 250 meter long wells. The second phase we had hoped that we could heat a bit longer, hence a longer production profile and possibly and get connection between the two well bores, reproduce back, we still didn't see connection, but in the third cycle we achieved what we wanted, we thought we can actually drain the [error] on both wells. So the upper wells would flow into the lower ones and it could recall with us. Obviously, it's still limited by the 150 barrels per day pump capacity.

Mark Friesen - RBC Capital Markets

Okay, very interesting. Just one more question about flexibility around the 2014 capital program. What would you see as being sort of a best case capital programs for ‘14 and maybe as a part of looking at financing options. Would there be an opportunity to sort of monetize infrastructure that you have invested in the deep basin and what do you think that would be worth?

Brent Heagy

Well, yeah, certainly, this is Brent Heagy. Yeah, we certainly see that there's opportunity to monetize the infrastructure, there's actually several ways that we could do that and we are looking at that. I think the important thing for us around the infrastructure. If we were to do that pay per transaction, certainly we would like to maintain a degree of consult, that's really important for us in that area. So, that we have the monetization of the infrastructure to point is certainly an option. Currently you know we have not set a budget for 2014 as of yet. Certainly we are going to be heading into that planning process later this summer and into the fall and obviously are getting certainty around the Put/Call is going to determine what that budget will look like, but certainly right now at the time we will absolutely continue on with hanging stone, one, which is the project that we sanctioned. As Sveinung has mentioned, I think you know we would also look at a bit of the money program and I'll maybe get Rob to comment on that. And then also depending on our funding situation, we will certainly look at delineation in the Duvernay.

Rob, is there anything you would like to add to that?

Rob Broen

Well, the only thing I would add is you know our land tenure in both the Montney and Duvernay is really good. So we are kind of in fortunate position that we have some choices on both program size and the pace that we developed. And so for example 90% of our Montney land is held into intermediate term. And in the Duvernay, we really only need to fill 13 wells above 95% of our high grade at 200,000 acres of Duvernay land. So that gives us some choices. I can tell you that operationally, we're preparing for small program in the Montney for Q4 and also for Duvernay land retention and delineation program. So pending the results of our review, obviously pending the results of Dover carrying and subsequent click and our internal review of capital allocation will be prepared to execute a program in Light Oil, but we still have to go through those stages and get board approval for that.

Sveinung Svarte

Obviously, Mark, our board will not sanction project unless they know they can't pay for them. So for them to see the next weeks panel decision is an extremely important milestone and that's why we're probably waiting two or three more weeks to firm up the what Rob likes to in the field to go under more wells in both Montney and Duvernay.

Mark Friesen - RBC Capital Markets

Okay, just to may be push a little bit. I think a number of about 200 million been used for deep basin infrastructure value, is that a good workable number or what do you think?

Rob Broen

Let's talk about value about later.

Operator

(Operator Instructions). Your next question comes from Mike Dunn from FirstEnergy.

Mike Dunn - FirstEnergy

Couple questions for me. Just on the Keyera facilities work that's being done in September, do you folks anticipate essentially being unrestricted in terms of your production capabilities following that work at Keyera?

Rob Broen

Mike, its Rob here. Just on Keyera, just to remind you that there is kind of two issues there, one is software recoveries at their plants and the second is the ability to handle liquids and we work very closely with Keyera over the last number of months and Keyera has done a number of short-term interventions, it includes things like putting in (inaudible) and adding some heat exchangers to stabilize liquids.

They do have some further modification that is doing during their plants turnaround in September. So we are pretty pleased with Keyera's response and we believe they've taken the right steps. The reality is in June, the Keyera plant had good runtime and we resume continuous operations in June and we have been adding wells in as the quarter progress. So we are not really limited right now by Keyera. Having said that, we are looking forward to completing the rest of modifications after September and then we don't anticipate more on plant interruption going forward. And just to add on Keyera does have plant projects longer term that will give additional assurance to steady runtimes on that plant.

Mike Dunn - FirstEnergy

And guess, where I was going with those questions gentlemen was, I guess a few months ago, you had guidance for exit sort of mid-year production. I think it was 11,000 to 13,000 BOE a day, obviously wasn't expecting to, that was kind of null and void with the Keyera issues there you found, but just trying to get a sense of where we'd be today as we were not restricted. So any comments you have on that?

Rob Broen

Mike, I can give maybe some color around production. So, I mean, you recall that our first significant production came on stream in late Q4 2012 and the guidance was established before the Christmas and now it's really based on test capability with those established production runtime. And so our production forecasting has been complicated by both third party service interruptions and then also the installation of artificial lift on well sites and the two go a bit hand in hand to (inaudible) in order to stabilize our artificial lift installations and just stable production.

And then Sveinung mentioned we drilled 8 pure well than we planned and that was -- this is to reallocation capital in order to optimize our well performance and we did that in a number of ways and one ways is bigger frac in some of our Montney wells, the installation of artificial lift and then significantly to complete the infrastructure projects of course from first strategy and also have increased value in the area.

And then the last thing I will mention is there were three horizontal wells, the late in our program in Q2 in Kaybob West and we don't intend on producing those. So the result of all that is midyear production in June is 8550 BOE per, that's 50% liquids and we are pleased with that.

We do have seven additional Montney wells to be tied in, but the reality is the expectation as we get those tied in is just essentially offsetting decline. So (inaudible) key for us to get it optimize and get our volumes up, but we do have all the wells tied in from the winter program.

Mike Dunn - FirstEnergy

And I guess separate topic, regarding the regulatory process, Dover. Can you just maybe talk through any precedence in the past that you are aware of where SAGD project saw material changes to I guess to the scope at this stage of the regulatory process, I'm not aware of any, but just wondering if you are?

Rob Broen

Actually I think Mike we are not aware of any of this. So first was the public hearing is the part of normal regulatory process in Alberta and lot of oil sands projects have gone through that before they get approve. So with the Dover project which was finished early May, the final hearing date, we really don't know any precedence project that has been changing scope that late in the process and obviously the project get define according to the rules of the (RCB) and all the (FIR) that you know you get too has been answered adequately and we believe the project will go, but we still need to get the panels additional that and hopefully that comes out next week.

Mike Dunn - FirstEnergy

Okay. And then just to review the timing, let's assume we get an announcement next Tuesday, let's assume it's an approval or recommendation for approval from there, how long is that, does that typically take until the cabinet signs off on that?

Sveinung Svarte

Well, it would have to be, if that panel decision is yes that's write-off goes over to the Alberta cabinet and I think the first meeting is just after long week in early September, we probably want them to get on the first meeting so maybe we can't meet September but again this is not complete in our hands either, it's not in our hands at all and then obviously it goes from the Alberta cabinet over to the Alberta Environment for the final approval probably early October.

Operator

(Operator Instructions) Your next question comes from Matthew Taylor from National Bank Financial. Your line is open.

Matthew Taylor - National Bank Financial

What are your plans for your Light Oil acreage outside of greater Kaybob and how are you going to keep up with expiry strategic specific to kind of monetize those assets over the next few years?

Rob Broen

Okay, it's Rob here again. So you know, our focus clearly is on our core acreage that's in the Kaybob area and that's where our Duvernay and we've talked about our 350,000 acres that has greater than 10 meters of thickness and then our real focus is the 200,000 acres that's greater than 20 meters thickness. And then we have worked really hard in the last few years to zero in on the core areas in the market and we talked about those this morning. So outside of that, we have a large position in Northwest Alberta in the Caribou area. We also have one in the Muskwa area. Those are 650,000ish acres each and those are still long-term exploration options for us but you recognized that we have a lot of non-core acreage outside of that.

I mean, we have over 2.8 million acres of land in Alberta. So we're working hard on deliberate strategy, two categories Orlando is core or non-core and the stuff that's not core will attract capital from us. So we will look at options to monetize [for amount] whatever we can do on that acreage. So that shouldn't distract anybody here on our base.

Matthew Taylor - National Bank Financial

Thanks, Rob. Just a secondary question on the Light Oil business unit. Costs are coming down. We saw that quarter-over-quarter. Where op cost kind of at the end of the quarter stand? Where do you guys target those to trying to say in 2014?

Rob Broen

So our operating cost for June was just over $10 a BOE and the reality is we see a line expect to get that trajectory is down a bit $70 per BOE and we're early still in the phases of production, we are only six months into our production seven months and there is lots of things that we can do to lower operating cost. We're working on electrifying our well size and getting rid of rental injections schedule with permanent facility. All of that will lower our operating cost. So we're pleased to report what we are adding and we definitely see a lower line to save property cost.

Operator

(Operator Instructions). This concludes the analyst Q&A portion of today's call. We will now take questions from the media. The first question comes from Claudia Cattaneo from National Post, your line is open.

Claudia Cattaneo - National Post

I was just wondering about the appeal process to the Dover decision. And so I just like you to clarify that, what is the Fort McKays appeal the regulators decision, so does mean that you are still getting your cash from PetroChina and the appeal then becomes PetroChina's problem?

Rob Broen

Hi, Claudia. Obviously an appeal for the first rights is limited and they must be applied for within 30 days after the panel decision. The regulatory process would not be posted because of an appeal, it actually goes in (inaudible). So the project would still receive regulatory approval as required under the agreement with PetroChina.

Claudia Cattaneo - National Post

Okay. And but have you talked to PetroChina about the possibility of an appeal and whether they're still prepared to pay up?

Rob Broen

I don't think we talk about the appeal process with anybody at the moment. We have to see if it comes first and obviously if it gets appeal, we have to see what consequences get for the project approval, but normally you should get project approval even if there was an appeal pending. But as I said the appeal rights are very limited and basically there hasn't been many projects that successfully been appealed in Alberta.

Operator

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

Andre De Leebeeck

That concludes today's trajectory. Thank you for joining us. Our call is now complete.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Athabasca Oil's CEO Discusses 2Q 2013 Results - Earnings Call Transcript
This Transcript
All Transcripts