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Executives

Bill McCaffrey - President & Chief Executive Officer

Dale Hohm - Chief Financial Officer

Don Moe - Vice President of Marketing

John Nearing - Controller

Helen Kelly - Director of Investor Relations

John Rogers - Vice President, Investor Relations

Analysts

Sam Rock (ph) - RBC

Chad Friess - UBS

Matthew Portillo - Tudor, Pickering, Holt & Co.

Mike Dunn - FirstEnergy

MEG Energy Corp. (OTCPK:MEGEF) Q1 2013 Earnings Conference Call April 24, 2013 9:30 AM ET

Operator

Good morning. My name is Laurel and I will be your conference operator today. At this time I would like to welcome everyone to the MEG Energy Corporation, first quarter, quarterly 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).

I would now like to turn the call over to Mr. John Rogers. Please go ahead sir.

John Rogers

Thank you Laurel and good morning everyone and thank you for listening into our first quarter conference call. In the room with me I have Bill McCaffrey, our President and CEO; Dale Hohm, our CFO; Don Moe, our VP of Marketing; and John Nearing our Controller and of course Helen Kelly and myself.

We’re going to follow the usual format of Bill giving his feel around the quarter, John is going to give us a bit of an update on the marketing side and then we’re going to open it up to Q&A.

As usual with MEG, we are going to talk about a lot of things that are upcoming for us, so I do have to remind you that we will be using forward-looking information. We’d like you to refer to our quarterly report or other filings on SEDAR to reference all of the cautions around that.

So with that caveat, why don’t we turn it over to Bill and give us his remarks on the quarter. Bill.

Bill McCaffrey

Thanks John. Good morning and welcome to our first quarter conference call. I said before that we see 2013 as a transformational year for MEG, that represents the accumulation of years of hard work on various fronts and as our efforts on the upstream and all along the value chain begin to payoff, we think its going to be a very exciting year.

There’s a range of strategic initiatives that have been underway, but before updating you on some of them, I want to take a moment to offer two major points of interest that have occurred during the first quarter and these are first of all price differentials in the North American oil markets and in particular how they play out into MEG’s financial position; and secondly our cost efficient production growth.

I’m going to start off just with a discussion on the widening differentials, which clearly impacted our financial performance in the early part of Q1. Now while the differentials in January and February were difficult for the industry, in the case of MEG they certainly reinforced the value of our role operating cost position and the importance of a diversified marketing strategy to reach higher price markets. And despite the volatility of differentials in Q1, our financial position has remained very strong.

We continue to make steady progress on our 2013 capital program and we are on track with our plans to reach 80,000 barrels a day by early 2015. We have all the financial resources in place to reach the 80,000-barrel target and while our market access plans that are currently underway in combination with the production ramp up will significant strengthen the corporations cash flows, its important to realize that we do not need to count on this cash flow to be able to fund these phases of development, this particular phase of development.

Also of note, the corporation is well positioned with the respect to its debt. All of the debt is covenant right and not subject to a borrowing base. Our un-drawn $1 billion revolving credit facility has four years remaining and the nearest maturity of their outstanding debt is 2020, which is well beyond the point the corporation believes it will begin to be in a positive cash flow position.

Now Don Moe is going to talk more about the marketing front in a few minutes, but before he does, let me take a moment to talk about some of the really exciting things that we think are going on in the upstream right now. On that point, I’ll start with a recap of our operational performance for the first quarter.

I know it’s still early in the year, but I got to say, I’m pretty excited about what I see so far. In Q1 we achieved record quarterly production of more than 32,500 barrels a day at a non-energy operating cost of $8.80 a barrel or said differently, $10.40 a barrel non-operating, our net operating cost basis, which we believe is among the best in the industry. The plant continued to perform very well and we continue to make great strides with the RISER initiatives.

Now we’ve covered this before, but to recap, RISER is a three-part initiative that improves the steam-oil ratios of our existing operations using proprietary eMSAGP technology and then what we do is we re-deploy that steam to our new pre-drilled wells. And then to manage the incremental production, the third part of RISER involves low cost debottlenecking at the plant.

So where are we at with all this? Well in Q1 the performance from the initial eMSAGP wells continue to demonstrate an industry leading performance with an SOR of just 1.3. The expansion of this initiative to Phase 2 area is now underway and it’s well under way.

We’ve begun to inject natural gas along with the steam in to mature SAGD chambers and also commence with the drilling of the offsetting in-fill wells. To-date we drilled 32 of the 37 planned in-fill wells and started the process of tying them in in March, and by the end of Q1 as part of the eMSAGP process we had begun co-injecting natural gas and steam into three SAGD wells and had put the first three of the in-fill wells on production.

Now it’s early in the production history, but the three wells to-date are producing between 300 and 800 barrels a day each. That’s exciting! We’re very pleased with that. Combined with the natural gas injection and the SOR for these eMSAGP wells has been reduced to roughly 1.7 thus far and the performance to-date is similar to or perhaps even better than the initial pad-A eMSAGP wells at this stage and we expect the SOR’s will continue to trend down as we increase the natural gas injection to displace more steam.

The freed up steam that’s been redeployed to start up three new per-drilled SAGD wells for us in Q1 and has contributed to the record core reproduction. Now we’re going to continue to bring on more eMSAGP wells throughout 2013 and anticipate that the majority of the 37 new in-fill wells will be tied in and producing by the first part of next year. Right now we are thinking that would be adding an additional six eMSAGP wells in two operations in Q2 and then we’re going to build from there.

Now next month, as part of the RISER initiative, we’ll begin modifying our processing facilities to handle anticipated increases in production. For a two-week period at the end of May, the electric grid operator is planning to take system upgrades, to make system upgrades to the electric grid, which will disrupt our power supply.

So although during that period of production we’ll be reduced by about 30%, we’re going to take advantage of the time to make some of the modifications to the plant that are associated with RISER. Modifications are pretty straightforward. They just involve the instillation of a large feed exchanger and some connections and water treating facilities.

We believe that the majority of the maintenance needed this year can also be done during the same time. So as a result we no longer think we are going to do need to do full plant turnaround this year. We may have some modifications throughout the year or changes, but the full plant turnaround that will typically occur in September is no longer planned.

When the last piece of equipment is delivered and installed in October, we’ll then begin to ramp-up throughput volumes for Phase 1 and 2 and we are thinking we can get to 35,000 to 40,000 barrels a day, which is up to 60% greater than the original design. Absolute levels will require production testing, but we currently believe this is achievable.

We are also carrying learning’s from Phase 1 and 2 over to Christina Lake 2B, as we look to drive similar increases over the original 2B design capacity, effectively making 2B RISER ready at the start up. Phase 2B continues to be on schedule with first steam beginning in late Q3. Following any components of targeted to be fully operational in Q4 and cost are projected to remain within the budgeted range.

The accelerated production associated with RISER on Phase 1 and 2 in combination with production from 2B will form the basis for nearly a three-fold production increase to 80,000 barrels a day in early 2015. We believe that the added production in combination with the significant value up-lift of each barrel associated with our hub and spoke marketing strategy will create meaningful increases in our cash flow in 2014 and beyond and will significantly enhance the internally funded portion of the development capital for future phases.

So what I’d like to do is turn the mic over to Don Moe to provide some details on the broader market and more importantly, MEG’s plans and progress to be at the leading edge of that market. Don.

Don Moe

Thank you Bill. Regarding market trends, the differentials began narrowing the margin and since tightened even more in April and May. In April the WTI/WCS differential narrowed roughly 26% and now that the May differential have firmed up, you’ll see that they are further tightened to approximately 16%. The forward market for the remainder of the year 2013 is not that good, but it is reasonably strong.

The exciting part of the equation is that the strengthening comes at the time when the macro factors are beginning to move in favor of up-stream producers and at a time when MEG specifically will begin to see meaningful value and increases for its crude oil as we grow production volumes and move past congested areas toward higher priced markets.

We are beginning to see some improvements in the continental pipe connections with the early moves focusing on connections between Cushing and the US Gulf Cost. Perhaps with the southern part of the pipeline congestion between Cushing and the Gulf Cost, well we still need to be able to get into Cushing from Canada either directly of via Chicago.

We are well positioned to take advantage of the Flanagan Seaway system when its completed mid-next year and we are continuing to activity pursue our own solutions that give us earlier access to higher priced markets.

On the macro side, aside from Cushing there are a number of initiatives coming to fruition, but in aggregate they are favorably on Western Canada prices. The market is generally seeing this improvement now with both event to WTI and the WTI/WCS differentials improving in the forward markets.

Looking at pipelines, most prominently the opening up of downstream distribution systems is allowing the seaway pipeline to operate closer to a 400,000 barrel per day capacity, helping to relieve pressure out of the mid continent and the very recent reversal of the Longhorn Pipeline which will move up to 225,000 barrels a day, away from Cushing and directly towards the U.S. Gulf Cost.

A little further out in time, TransCanada's Gulf Coast pipeline project continues to be on track to be operational in late 2013 and that’s expected to significantly improve the prices in the Cushing area. Collectively these changes will serve to largely eliminate congestion out of Cushing. We believe that these changes will make a substantial improvement in restoring connections and in making those connections to international crude oil prices and our fundamental step towards eliminating the volatility related to dislocations in local markets.

Now for North of Cushing, on the slate also for this fall is the size of BPE rating conversion of roughly 240,000 barrels a day converting from LIBO to heavy oil, more than offsets new heavy oil entering the markets from Canada this year. In the immediate interim, Enbridge's Flanagan South pipeline, which includes the looping of the seaway pipeline and make a direct connection from Chicago to the U.S. Gulf Coast remains on track for mid 2014 in-service date.

In the longer term, while the industry is awaiting the decision on the Keystone XL pipeline, MEG’s choice to take out capacity on the Flanagan South pipeline rather than Keystone XL avoids any direct reliance on the Keystone XL decisions.

Moving away from the macro look of the North American markets, we are making progress in getting the wheels on our hub and spoke marketing strategy rolling, starting with the implement of two new market spokes this year. These spokes will provide access to much higher priced heavy oil markets at Gulf Cost refineries that are struggling to maintain supplies of heavy crude sources from places such as Mexico and Venezuela. Direct and early access to these minor priced markets through bypassing mid congestion and price dislocations is a key feature in the hub and spoke strategy.

The first major spoke in our acquisition of barge is to reach customers along the U.S. inland waterway system from the mid continent and all the way to the U.S. Gulf Coast. We have targeted BME to take delivery of barges as part of this spoke in midyear 2013, but I’m happy to report that MEG has already taken delivery of the first list of barges. They are now in the water and we are now delivering our first product shipments. We will continue to accelerate this market spoke as we take delivery of additional barges through the middle of the year.

Our next major spoke involves large volume rail shipments with the planned completion of our wholly owned Stonefell terminal and from there a pipeline connection to an adjacent third party rail loading facility. With this spoke in place in the second half of the year, we will be able to reach a broad array of costal refineries in Canada and the US, again directly accessing international prices.

We are seeing a lot of interest from a broad range of refining customers and as the volumes through these transportation measures of barge, rail and ultimately the Flanagan South pipeline grow, there is tremendous upside to the market value of our crude oils.

I’ll wrap up by saying that these moves have been in the work for some time and we see them providing both an early connection to international prices and the long-term benefit of meaningful transportation options.

Thank you Bill.

Bill McCaffrey

Thanks Don. Well from Don’s comments I’ve underlined the long-term benefits of the hub and spoke marketing strategy and having a full suite of pipe, rail and barge transportation spokes.

The moves we’re seeing on the ground this year are not just the short term fix to get ahead of the market, although we clearly expect to be just starting to see early benefits, but it’s the bigger picture that really is critical here. This is a long-term strategy to ensure that we’re in the driver seat with flexibility around all market options and we will continue to advance this strategy beyond the reasons that’s discussed as opportunities become available.

We want and expect to be in the position to have a choice of the market and not to be constrained by issued related to any particular piece of infrastructure or specific market region.

As we continue to take control of the value chain and reach markets that trade at international prices, the solutions we’re putting in place are expected to fundamentally change how differentials have traditionally been factored into our business. So rather than think of the value of our crude oil in terms of WCS/WTI discounts, it will soon be thought of more along the lines of the type of crude oils our brands will compete with in the case of the Gulf of Mexico, notably Maya, with net backs adjusted only for the transportation cost, to get our barrels to those markets.

With the advancement of the RISER initiative and the completion and start up of Phase 2B and the volumes and cash flows that come from these two major projects in 2013, with the completion of Stonefell and its tie-ins to rail facilities also in ’13 and the launching of our barrels to higher priced markets, thus bypassing congested areas again occurring this year, 2013 is truly a transformational year for MEG.

I’ll turn it over now back to John and we’ll be prepared to answer any questions you may have.

John Rogers

Great. Thank you Bill and Don for your comments on the quarter. Laurel we’re going to open up the lines for questions now. Once again, I would like to remind everyone that Helen and I will be available after the call to deal with your specific modeling questions. So with that, why don’t we open the lines for questions?

Question-and-Answer Session

Operator

(Operator Instructions). And your first question comes from the line of Sam Rock (ph) with RBC. Your line is open.

Bill McCaffrey

Good morning Sam.

Sam Rock (ph) – RBC

Good morning gentlemen. So just two questions from me. Firstly one capital cost in general and how it pertains to Chrsitina Lake Phase 2B and secondly on Board Membership.

So on capital cost we’ve seen a few recent announcements alluded to increased construction and service costs and it seems like you might be nearing the capital budget, the $1.4 billion capital budget on Phase 2B. So understanding that there have been some changes there, how should we think about adjusting our capital spending expectations for Phase 2B, including the RISER portion of that?

Bill McCaffrey

The capital for Phase 2B is still low within its budgeted range. RISER has its separate budget associated with it and right now for RISER we feel that is also right on track. So within the forecast of what we’ve looked at, we don’t see changes at this time.

Sam Rock (ph) – RBC

Okay, thanks Bill. So secondly on Li Zheng’s departure or not standing for real action in the next board meeting here, are there any possible implications for CNET’s holdings?

Bill McCaffrey

No, CNET is a big supporter of the company. I have talked to them over the last sort of while with regard and they are extremely committed. They see MEG as a financial investment for them. They have restated that to me on several occasions, so I would see CNET as a long-term value focused shareholder.

Sam Rock (ph) – RBC

Great. Thanks Bill. That’s all for me.

Bill McCaffrey

Thank you Sam.

Operator

Your next question comes from the line of Chad Friess with UBS. Your line is open.

Chad Friess – UBS

Good morning. I was wondering if we could walk through some rough math on the financial side of things. I think in the past, either officially or unofficially and correct me if I’m wrong on that, the company has stated that it’s effectively funded to reach around 80,000 barrels a day in early 2015 without requiring an equity issue. So with cash on hand right now, about $1.9 billion and a little over half of that billion will be left by year end; if you spend $2 billion again next year, even with a lot better cash flow, that will require you to effectively draw on your credit line almost fully.

So I guess my question is, are you comfortable cutting it close to the bone and/or there’s some leavers that you might pull such as another debt issuance, the reasons throttling back the capital spend next year.

Bill McCaffrey

Thanks Chad. Yes, we haven’t really set our budget for next year. Our focus right now is on two major projects and that’s RISER and Phase 2B. Those projects will generate meaningful cash flow for us.

We certainly do have the debt markets open to us. We’re not contemplating any equity raise at this time and we do have lots of flexibility on the timing of the 3A, which we actually need to do some work in that area anyway. So we are actually feeling that we’re in pretty comfortable position that we do have a lot of options, and we’ll make those decisions later on in the year. So it will be too early right now to actually take a look at the timing and sequencing, but sufficed to say, we do have a lot of options.

Don Moe

Chad, I do want to remind everyone, when we’re talking about 80,000 barrels a day. That’s a combination of a number of things that we’re doing this year. Its 2B and we will complete 2B this fall and its Phase 1 and 2 with the RISER initiative in effect in Phase 1 and 2. So those are the two pieces to get us to 80,000 barrels a day. It doesn’t include any production from future phases of anything like that. Its from 1 and 2 with RISER and 2B without RISER. So that’s how we get to 80,000 barrels a day.

Bill McCaffrey

I think (inaudible) rate is a good point. As you see from our conversation at the front end, we are actively in motion if you want with RISER and you know that Phase 2B is nearing completion here in this year. So these dollars are already, these are the backbone dollars to RISER and the Phase 2B; said differently these are the backbone for the production to go to 80,000 barrels a day. So RISER in combination with 2B will get us there.

Chad Friess – UBS

Okay, thanks for that, and is it fare it say that you are determined to show the market 80,000 barrels a day before you come back to it, regardless of plans on Phase 3.

Bill McCaffrey

We haven’t made any decisions in that area, but we are moving. On 3A what we are doing right now is we are conducting engineering, we are clearing the site, so that we can be prepared. We got strong lead-time items ordered. Our focus on 3A is to standardize design, so we can use it again for future phases, whether they are Christina Lake, Surmont or Growth Properties and we are identifying synergies with 3B, since 3B is adjacent to 3A.

And then the other thing we’re going to do is, we want to incorporate any plant modifications in the design upfront that would be associated with things that we are seeing on the RISER initiative. And keep in mind, on RISER we are making the changes as we go through the year and then we anticipate that it will about 35,000 to 40,000 barrels a day, but we’d like to see how that plant performs and that will give us some guidance into what things we’d want to on 3A.

So in a lot of ways the things fit very well together. We are making tremendous progress and we are positioning Phase 2B to be RISER ready and we are looking at the standard design of 3A and beyond to say how should this look.

So we are not in a super rush to build 3A right at this moment. We are keeping it on track and moving it forward with the long read and engineering, but we actually need the time to look through what is the right standardized design.

Chad Friess – UBS

Okay, understood. And I was wonder if you could give me some rough guidance on the shape of the deliveries by way of barge and rail to the U.S. Gulf Cost. Are you thinking about 10% of production in Q2, rising to maybe 50% by year-end, is that reasonable or do you see something different. And also do you think that there is something close to Maya pricing is achievable or how much of a discount to the Gulf Cost, heavy oil benchmarks do you think is a reasonable thing to model.

Bill McCaffrey

Yes, right now what we’ve got is we anticipate having all of our barges by Q3. We have mentioned we have received some and we are moving barrels. That gets stronger in May and June and beyond, and so we think we’ll have them all by Q3.

And then what we are focused on right now is creating the contracts as Don mentioned, but we are seeing huge interest from the refineries in this area. We pretty much have most refiners talking to us and looking to get barrels and of course when your in this position that we’re moving into, you are going to make sure you do the right deals and have the right flexibility. So we’ll see that changing as we go through the year.

And then when we look at the pricing of it, and to answer that question directly, its kind of a scale. We think it will grow over time and it’s hard to know exactly on a month-by-month basis what we’ll do, because we are putting contracts in place. But to a degree that we end up getting the barges and everything, then we have the flexibility to move forward with those contracts.

Now on Maya pricing, yes we think that we will be able to – once we control the value chain, we think or barrels will compete with the Maya type crew. There may be small adjustments on that price based on refining value, but very close to it.

And if you took today for example, WTI is at 89, Maya is at 96 and Brent’s at 101 and so you should think about – say even when I was talking earlier, I think we are actually going to have to rethink how we talk about our business and the word differentials in WTS and WTI don’t mean much any more. Its more about if we could trade at or near Maya type crude, plus transportation, that’s the value and obviously if Maya is at $96 a barrel, that’s a huge, huge impact.

Chad Friess – UBS

Great. Those are my questions. Thanks guys.

Don Moe

Thanks.

Bill McCaffrey

Thanks Chad.

Operator

Next question comes from the line of Matthew Portillo with Tudor, Pickering, Holt. Your line is open.

Matthew Portillo - Tudor, Pickering, Holt & Co.

Good morning guys. Just two quick questions from me. Just in regards to the last question, I was hoping that you could potentially give us a little more color on kind of the access to the Mayan market. And as we think about a $95 per barrel pricing, by the end of this year if we assume that pricing was flat, how should we think about your kind of net realizations as we back out transportation costs.

So you’re trying to get a better picture of from the $30 per barrel on bitumen price that you realized on Q1, how could that progress over the year and how should we think about that bitumen price longer term if you are able to access Maya type pricing.

Bill McCaffrey

Sure. Well we had three spokes that could do that. We have the barge, rail and Flanagan out next year and I really think Flanagan is a pretty exciting way. It doesn’t much press there, which is a good thing I think relative to Keystone, but to us that’s everything in terms of the pipeline part of it. Its moving fast. It complements our barge and our rail well.

But even for mentioning those three, just think of the net pack as if we are moving it by rail it will be about a Maya type pricing. I’ll give it a few dollars plus $15 to $17. If we are moving it by barge it might be the Maya range minus $13 to $15 and then as Flanagan comes in mid next year and its right on track for that right now, it would be considerably less than $10. They might have to use that (inaudible) or because they were under confidentiality.

But its pretty simple math; you would take your expectorants of Maya and adjust it for the transportation and maybe $1 or $2 more on that and then that’s where you are going to end up.

Now its an important point that its not as mechanical as this barrel went down by barge there, this other one goes by rail. If we have the option and we clearly do, we think all of our barrels will see the influence of the optionality that MEG is creating, and that is real key to our whole strategy.

As I said in my part earlier, we want to have the option to move barrels any way and so its just like anything. If you think of the pricing and we only had one customer that we could sell it to and he had a lot of options, your price has a certain value based on that.

But it we have a lot of options, which we clearly are generating here and the type of the customer that we used to sell to was in need of crude, you could see why that would fundamentally change the pricing conversation, and in a lot of ways that what differentials have grown to become over the last few lots. Who has the options to either supply, in terms of the supply and demand equation.

Don Moe

Matthew, I’m just going to give you a bit of a read on that. So with the cash operating netback, we are talking about 1 barrel here this quarter where we were around $17. If for that particular barrel we’ve been able to achieve Maya pricing, that cash operating netback would have gone to over $50.

Matthew Portillo - Tudor, Pickering, Holt & Co.

Thank you, that’s very helpful. And then just in terms of the marketing, could you talk a little bit about your access to condensate and how you view that progressing over time with the hub and spoke model in place, kind of additional condensate growth out of U.S. and how you guys kind of view the condensate market over time and the ability to potentially access some cheaper condensate.

Don Moe

Sure, happy to do that. Yes, when we talk about the hub and spoke we launched barrels in various ways. The thing that we haven’t talked much about is we also have a gathering system that parallel got in reverse if you want. So in other words, we are tiding to the fractionation plants in the Edmonton area, where their condensate is stripped out.

We also bring in condensate from throughout North America. So we look to get stranded barrels of condensate by rail. Stonefell is a hub and a critical factor of this, because its one thing to be able to get access to large amounts of condensate, but you have to be able to hand it and Stonefell will be able to do it.

So Stonefell is a duel pipeline system that acts as a relay, so when we talked about moving our barrels to the Edmonton, to the Stonefell area and then launching into these various ways, we can put condensate back in the reverse way on the second set of pipes that lie in the same ditches as the ones that moved the blend.

So we are focused on capturing stranded barrels of condensate and brining those up via our well into Stonefell, launching those into access pipeline and sending them up to the field at very, very cost effective ways and we are looking at a number of other initiatives, which I really cant go into right at this moment.

Matthew Portillo - Tudor, Pickering, Holt & Co.

Great, and then just a final question for me. I know the mid-stream part of our business is an extremely valuable and kind of key focus for the company, but just curious as you guys think about progressing kind of 2014 and 2015 to be on with all these different opportunities from a marketing perspective open up.

Is the mid-stream potentially an asset that you could monetize over time to help fund additional upstream investment or that’s something you really like to keep within your portfolio and so we operate in that asset.

Don Moe

Yes, we see it as a key asset to the success of the company. If it was more operational today, you wouldn’t have had a first quarter result like it is and this is key to the long-term prosperity of the company. So no, its very, very strategic for us.

Matthew Portillo - Tudor, Pickering, Holt & Co.

Thank you very much.

Bill McCaffrey

Thank you Matthew.

Operator

(Operator Instructions) Your next question comes from the line of Mike Dunn with FirstEnergy. Your line is open.

Mike Dunn – FirstEnergy

Good morning everyone.

Bill McCaffrey

Hey Mike.

Mike Dunn – FirstEnergy

Good morning; a couple of questions. First gentlemen, just wondering if you could comment on Maya pricing versus Brent has been really tight. Are you aware of anything specifically that’s going on in that market or in terms of specific refinery or supply disruptions or is it just more of a macro reflection of the tightness.

Bill McCaffrey

Yes, thanks Mike. I think what we are seeing in the international market is a reflection of the difficult that particularly the U.S. Gulf Cost refineries are having to keep up with getting supplies of Mexican, Venezuelan and (inaudible) and so what they are doing is they are pricing those up on the Gulf Cost.

And I think that’s just the natural response to them not being able to achieve full supple, and I think that’s kind of the nature of what’s happening in the world. Certainly relative results and that’s in a way I’m very comfortable when we go to the Gulf Cost with Canadian volumes that we won’t have really much difficult competing with those kind of barrels on the Gulf Cost.

Mike Dunn – FirstEnergy

Sure and next question guys, in terms of the general and administrative costs, obviously they have been inching up over time as your sort of getting closer to bring on Phase 2B etc. On a per barrel basis they are still high and I guess my question is sort of longer term, do you have sort of a target view in terms of a per barrel G&A cost? I think we are running may be $4 or slightly below for next year, but I guess we are worried we are too low on our estimates there and how I should be thinking about that going forward.

Bill McCaffrey

Sure. We are obviously a company that is build in steps for the growth and so I think the way I would look at it is its hard to estimate what component is somewhat fixed in this, but I mean we have the geologist, the geophysicists, the engineers all in place. We have operations staff. I think as we add phases, we are probably just going to add more operators, but a not a lot of the rest.

So you should start to get to see quite a bit of the economy of scale if you want to put it that way towards G&A, and right now because we have all the horsepower in place for the development of RISER and Phase 2B, but we don’t have the barrels that’s why you’d see the costs where they are.

Mike Dunn – FirstEnergy

Okay so no, there’s no sort of rule of thumb, $3 longer term of $4 per barrel.

Bill McCaffrey

I think you’ll see numbers improve as you add barrels, but I don’t want to put a number to it right now. Fractionally you should think about it that we are very well staffed, appropriately staffed for our growth and that as the barrels comes, that number takes care of itself.

Mike Dunn – FirstEnergy

Sure. Okay and then just a couple of other questions guys. On Phase 3A, I just wanted to get clarity. Do you guys have a feel for when you are going to decided how to proceed there. It sounds like not earlier this year at the earliest, but…

Bill McCaffrey

Yes, I think that’s right. I think we haven’t made that decision. We are doing a lot of legwork. The work I mentioned is all relatively low cost in the bigger picture. So it makes perfect senses to advance that part of the equation and keep it moving forward.

But I do really want to see the effects of the plant modifications to know that there’s certainty and what to do on those standards design and that’s going to take us as we mentioned. We get our last piece of equipment in October. We need some guidance ourselves in the sense of where we could go to, but its very exciting what we are seeing. It’s just being very careful and pragmatic on it.

Mike Dunn – FirstEnergy

Sure, that helps, real thanks. And just last question, just want to clarify; Phase 2B, the cost estimate excluding the RISER. Is it in fact still the same, the $1.4 billion that was talked about I guess in the past?

Don Moe

Yes we think we are in the ranges, as we said all along in the budget there. I think the way I’d look at it is on a capital intensity basis. If it wasn’t at 2.8, it looks like its about a 40,000 for a flowing barrel. At a 2.4 which would clearly be able to demonstrate on Phase 1 and 2 its a 37,000. And then the exciting thing as RISER comes in, that we did average about 1.7 overall for the life of that total package. Then that will take you down to about I think 24,000 and we feel pretty good about those numbers right now.

Mike Dunn – FirstEnergy

Great. So that 27,000 of flowing, that would include the additional capital for RISER?

Don Moe

Yes.

Mike Dunn – FirstEnergy

Okay, great. That’s all from me. Thanks folks.

Operator

With no questions at this time, I’ll turn the call back over to the presenters.

John Rogers

Well, thank you Laura and once again thanks everyone for your interest in listening into our conference call. Of course Helen and I will be around for the rest of the day should you have any further questions or any modeling questions, of course we will be happy to help you. Other than that, everybody have a good day. Thanks.

Operator

That concludes today’s conference call. You may now disconnect.

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