Delphi Energy Corp. (OTCPK:DPGYF) Q3 2010 Earnings Call November 9, 2010 11:00 AM ET
David Reid - President and CEO
Brian Kohlhammer - VP Finance & CFO
Brian Kristjansen - Canaccord Genuity
Ray Kwan - Macquarie
Good morning ladies and gentlemen, welcome to the Delphi Energy Corporation 2010 third quarter results conference call. I would now like to turn the meeting over to Mr. David Reid, President and Chief Executive Officer of Delphi Energy Corporation. Please go ahead Mr. Reid.
Thank you Thomas and good morning everyone and welcome to our third quarter 2010 conference call. As mentioned, I am David Reid, I'm the President and CEO of Delphi. I am also joined today by Brian Kohlhammer, our VP Finance and CFO.
We'll start the call with some general comments on the company's progress over the last quarter, followed by some specific comments on the third quarter financial and then provide some brief remarks as we look into 2011. And finally, we'll open up the call up to your questions.
Firstly, be advised, that statements made in this call other than statements of historical fact may contain forward-looking information and I refer you to the forward-looking statements disclaimer included in the MD&A attached to today's press release and inform you that this disclaimer applies to any forward-looking information disclosed in today's call.
For those of you joining us that are less familiar with Delphi, we're predominantly a natural gas focused E&P company, about 80% by-production in the third quarter with over 95% of our production in reserves and 95% of our undeveloped land located in the deeper parts of what we call the deep basin in northwest Alberta. We operated approximately 85% of our production and consistently operate about 95% of our field capital programs.
We are very pleased to provide some detail around our operating and financial results for the third quarter. We feel we have hit the mark on all our targets for the quarter. We had a very active third quarter in the field. We have now drilled all of our contemplated operated wells with a 100% success. The 12 well program 8.3 net was really focused on our light oil projects in Bigstone and Hythe, as well as our high NGL gas projects in Wapiti. By high NGL, I mean 50 to 100 barrels per million so very significant.
We do have approximately seven other wells on a gross basis that will be completed in fourth quarter, some of the non-operated stuff that is yet to be drilled, but we do expect that to happen in the fourth quarter. We did achieve our budgeted production target for the quarter, as well our light oil in NGL volumes remain very strong and we are very happy with the performance of those Doe Creek wells and the Bigstone Cardium wells.
Our operating cost efficiencies continue to improve helping our bottom line with our production growth really driving the efficiencies within our core areas, as well as we are enjoying the full benefit of the disposition of the non-core assets in east central Alberta.
Weather did have an impact on the e-capital programs, really minimal on the drilling program because we did get an early enough start in the third quarter, but it did affect the next phases of completion encrypting a tie in. So we really didn’t have a lot of new production on that benefit of the quarter, we will see that in Q4. We are starting to catch up. Our last operated well is being completed actually today as we speak, that’s the Doe Creek Horizontal. So we are catching up and we are looking to have most of our operated wells on production through the fourth quarter probably at latest year end.
From an operations perspective, overall we are very pleased with the test rates and initial production rates we achieved on the wells drilled over the summer. We have tried to outline in the press release as much data as we can, some of it's only test data, some of it's seven day tests but we are possible put in there the 60 to 90 day production performance of a number of the previously drilled wells to give you a sense of how well we are doing. And we are very pleased with the oil wells in both the Cardium and the Doe Creek and the success we are enjoying at Wapiti is going to play a key part of our capital program going forward with the liquids content that we do enjoy there. It competes very nicely with some other light oil projects that we are doing.
So from a financial perspective we have very strong cash flow on a per unit basis. Again just over $20 of boe, that is our target we are trying to maintain that, that’s despite very low gas prices, vehicle gas price in the quarter and that’s really in part due to the production mix of light oil and NGLs as well as heat content within our gas, our operating costs and cost structure improvements, as well as the hedge position that we have enjoyed throughout the year.
So before I turn it over to Brian, I’d just like to say we are very optimistic and confident in our ability to execute the go-forward plan through the winter drilling program in this rather challenging natural gas price environment, we are maintaining very strong cash flow and our fuel results are allowing us to grow within our cash flow.
With that, I’d like to turn it over to Bryan our company’s VP Finance and CFO.
Thank you Dave and good morning everyone, as usual I’ll answer any question you may have on the third quarter report at the end of our call. Right now I would like to elaborate on some key factors that have contributed to our success in 2010 from a financial perspective.
We continue to be focused on two primary objectives, maintaining our strong financial position and in this current level natural gas price environment and secondly generating a recycle ratio of at least 2:1. As we had talked before, we are focused on generating an operating net back up 22 to $24 per BOE and cash net back up approximately $20 per BOE.
These net backs are expected to provide re-cycle ratios of 2:1 which will provide us with the cash flow to pursue our planned capital program to grow production and reserves all at the same time add considerable value to the company for our shareholders. To accomplish this recycle ratio, we strive to achieve planning and development cost of $12 or less per 2P reserve edition.
Might as well the lower natural gas price environment we are in, operating efficiencies are critical in generating this higher net backup if possible for this re-cycle ratio. On the perspective of generating cash net back up of $20 per BOE as a significant natural gas producer in this commodity price environment. We are encouraged by a lot of the same points that David mentioned positive results we see in our production volume growth, particularly the change in our product production mix.
Our realized sales price and decreasing operating cost. Our realized sales price have been positively affected by several things. The increased production from our Bigstone Cardium and Hythe creek oil opportunities in combination with the sale of our East Central properties has improved our crude oil quality enhanced our realized sales price. Also, we continue to see the benefit of our hedging program, focused on natural gas, the gains of over 4.9 million in the third quarter. Our realized sales price has also improved due to the high NGL content of natural gas production at Bigstone and Wapiti/Gold Creek.
At Bigstone much of our natural gas production comes with 20 to 25 barrels per million cubic feet of gas and at Wapiti/Gold Creek that ratio is as high as 50 to 100 barrels per million cubic feet of gas. The NGL component because of significant value add to the cash flow of these projects, and our realized sales price. At Bigstone the all in effective gas price per Mcf including NGL revenue was 581 per Mcf in the third quarter, whereas at Wapiti/Gold Creek it was an equivalent price of 643 per Mcf. All these factors are contributing to a realized price of approximately $37 to $40 per boe to generate a cash net backup $20 per boe.
As a commodity producer it is critically important to minimize cost of production. Our largest control of the cost is operating cost. Over the past seven quarters we have been able to reduce corporate operating cost from a highest 1067 per boe to 745 per boe in the third quarter. This reduction in operating cost has primarily been due to growth in production volumes in our three core areas.
In each area we have acquired production and infrastructure and subsequently grown production in those three areas by three times or more to take advantage of excess processing capacity at the gas processing plan. This has spread the fixed cost over more boe's [hence one new] the infrastructure has resulted in new production coming on at a marginal cost lower then the field average.
In the third quarter the primary reason of the reduction in operating cost per boe was the disposition of our East Central properties late in the second quarter. Each properties represented less than 2% of production at 8% of operating cost or above $0.50 to$0.60 per boe of our corporate operating cost.
We believe further operating cost for boe reductions are possible due to the efficiencies of our core areas. These reductions are likely to occur at a slower pace. Other initiatives continue to be looked at to further reduce our operating cost.
As far as the strength of our balance sheet we continue to remain in a strong financial position with the debt to capital ratio 1.9 to 1, based on annualized first nine months cash flow of 43.3 million. We utilized our available credit capacity to execute the third quarter capital program equal to cash flow and the net proceeds of the equity offering completed in the second quarter.
Then that at the end of September 30th was 107.9 million on a credit facility of 135 million. The fourth quarter program was expected to be slightly less than forecast cash flow as the second half capital program is completed resulting in a net debt at the end of 2010 of 100 million to 105 million.
At this time, I just want to expand on our third quarter capital. In the third quarter we incurred capital of 43.9 million of which 36.9 million was incurred on drilling and completing 8.3 net wells. The average well cost was [suitable] 4.4 million. Included in that capital of 36.9 million was approximately 3.9 million for workovers and pre-completions and 2 million for wells which were not reg released before quarter end and therefore not included in the well count.
Deducting these items results in an average well cost of about 3.5 million. This average cost is consistent with increased length of horizontal wells and more [frac store] as outlined in the tables in the operation section of the Q2 report and the continued use of oil of based fracs. Our credit facility is currently being reviewed by our vendors as part of the schedule semi annual review.
With the collapse of the natural gas forward curves over the past six months, it is no surprise that the banks of lower the price decks for the purpose of determent the lending value of gas assets.
Being a significant natural gas producer, the lower price debt will be expected to reduce the borrowing base of those assets. There are several positive influences that we have outlined to our lenders which we believe will offset the gas price adjustment. These factors include our successful second half drilling program and the oil NGO reserve additions, continued production growth and particularly the change in production mix, much lower operating costs and the operating costs underlying our current lending value and positive adjustments to the borrowing days for royalty changes announced by the Alberta government since the determination of the $135 million credit facility. We believe these positive adjustments will more than offset the gas price adjustment resulting in reconfirmation of our current credit facility at a minimum. We anticipate releasing the results of the review over the next several weeks.
With respect to our hedging program we have recently undertaken a transaction whereby we have sold the US crude oil call on 600 barrels per day for 2011 and 2012 and use the value generated by that call to purchase the fixed price natural gas swap at $560 million per GJ or $6 an Mcf, just under 7000 gigajoules per day for April to December 31, 2011. This increases our hedge position in 2011 to approximately 20% of our natural gas production at $6.04 per Mcf. We'll continue to look for further hedging opportunities for 2011 for crude oil, natural gas and the basis differential.
Lastly, I would just like to touch on our market guidance for 2010. We expect to achieve the lower end of our cash flow guidance between now adjusted 57 to 60 million from 57 to 62 million for the year, but you'll not see this is a big change where we thought it was appropriate to revise our [April] gas price for gas forecast further down for the remainder of the year to an expected average for the year of about 395 per Mcf. Our most recent guidance was based on an equal gas price of 4.10 per Mcf.
I will now pass the call back to Dave.
Thank you, Brian. Just a little bit more on our operational highlights for the third quarter and how that helps shape the upcoming winter program, and I do advise you that the winter program and our fall 2011 capital program and production guidance will be out in probably 2 to 4 weeks. We are a little bit delayed, really waiting on some specific well results to help us finalize our overall 2011 capital program. So, I will try and give you a context in which we are thinking today, where we are going to be spending some money, it will be pretty obvious based on the results we have had, but it will be another two to four weeks before we ultimately release our 2011 outlook.
Based on our third quarter activity, focused in the Cardium at Bigstone and the light oil Doe Creek pool at Hythe, we are very pleased with the way that our light oil projects are developing. We did put a table of both projects in the press release for you to view and in some cases now we are well beyond the 60 day production tests, and very pleased with the way those wells are performing. And with the Cardium specifically, we do have a couple of vertical wells out there that have been on for as long as five years now.
So we are getting a pretty good handle on how these horizontal wells are performing relative to the verticals both from an oil production perspective and from a GOR perspective or the gas oil ratio. So, we are very comfortable that these wells are going to perform exceptionally well from an oil recovery perspective, even at what I would call a slightly higher GOR than a lot of the Cardium oil pools to the south of us. So we are very pleased with those results and we will be continuing to drill into 2011 within the Cardium. We have stayed with oil based fracs within the Cardium, we believe that, that is prudent with what we know today. We do have core up there and we are doing some regaining perm work on various fluid types, but for now we will stay with oil based fracs.
We have experimented with other longer horizontal wells in these last two. We had the opportunity to drill one that’s as long as almost 1,350 meters and we placed 16 fracs in that, one which is twice the frac interval, that's the very first Cardium horizontal we did experience. So, we will be interested to see how that performs over the next 60 to 90 days and we will be out drilling in first quarter with another round.
We do have three non-operated low interest wells that will be drilled through fourth quarter and we will be watching the operator which is Chronicle very closely and be learning anything new from that operation as well. Within the Doe Creek itself, that pool has been performing exceptionally well, but the production results are holding in there very nicely. We now have a number of wells with pretty solid production history and we will continue to develop that pool through 2011. We also have a pool to the north that we are 40% in with another operator that we drilled one well in there successfully. It’s a more mature pool than underwater flood for quite some time. That was successful we, we will see a second well drill there in fourth quarter. As far as the liquids-rich project area in Wapiti/Gold Creek that is a project area that we acquired in 2009 a very attractive metrics which included significant infrastructure that is paying dividends today, the production in Wapiti/Gold Creek at the time of acquisition was about 400 boe's a day.
Today we are 3000 boe's a day and with the wells yet to come on. We are thinking we are probably going to have a four fold increase in 400 up to 15 or 1600 as enter 2011. So that has been a great acquisition for us, and we have a lot of our opportunity in there and we will see significantly increased drilling program in Wapiti/Gold Creek as we enter 2011.
Largely because of the high liquids content of which a good portion of that is corn and seed so very near Edmonton restaurants pricing. So that will play a big part of our growth as we head into 2011 and take a little pressure of Hythe which has been a tremendous growth asset for us over the last couple of years. It is a much meaner NGL content gas up there so takes a little pressure of the growth there.
We have enjoyed tremendous growth year-to-date Hythe has averaged just over 3000 boe a day when we acquired that asset in 2007 it was doing 400 boe's a day. So there is a lot of room to grow there, we will just be taking a little slower pace as we head into 2011 there with the current gas prices. Likely, only drilling couple of vertical wells in the first quarter to help us delineate the Flair and Blue Sky Horizontal plays that we have been pursuing.
We need to get some core and continue to work on our frac full of design in there, we are not entirely satisfied with the results although positive from a perspective of getting gas out of that rock, we are not happy with the initial rates and what we think will be the ultimate recovery. So we think we have a lot of room to improve there and we will be fine tuning that program through 2011 and ramping it up as gas prices improve in to the $4 range.
In terms of our other activities through the third quarter in prior years we have been acquiring our un-developed plan generally through our property acquisitions. As the cost of the acquisition metrics have escalated especially in the deep basin where the focus has been on high NGL content gas. We have taken and shifted our strategy to more of an un-developed Land acquisition strategy and acquired just over 30,000 net acres in the Bigstone, Hythe and Wapiti/Gold Creek areas year-to-date grown quite significantly at very modest cost, we have been focused entirely up until now on the Cretaceous aged rock which allows us to pursue the sweet gas liquids [rich] and tie into existing infrastructure.
In post third quarter, we did step out a little bit and in Bigstone area we acquired some un-developed land generally a large chunk of that was Triassic to basement so we do have some Montney exposure as well as some Duvernay in that un-developed land that we acquired in the greater Bigstone area so we acquired almost 26 net sections out there and that isn't anything that’s going to move real fast, but it allows us to continue to build inventory as we head through '11 and into 2012. So, we are very pleased with how our inventory has been able to grow from an un-developed planed perspective.
So as we look into 2011, I mentioned our capital budget will be finalized here over the next short while, and as we continue to evaluate the results and incorporate that data into our planning, we do however have contemplated in our planning to drill [I guess] in horizontal at Bigstone, we have talked about that in the past.
In Wapiti/Gold Creek, our thoughts on the Nikanassin horizontal, we put that on hold for now we have had some excellent success in the vertical wells the Nikanassin is performing very well there and we are booking reserves and our independent engineers are booking them on a one well drainage of about an eight of the section. So we can delineate of the four wells per section as per regulatory approval and still have room, we feel to be putting horizontals on that same section.
So for now with this current environment we will stick with the horizontals, continue to delineate and enjoy some very cost effective production reserve balance in the Nikanassin. Some of the other zones have proved very successful as well. Our expiration success that we talked about in the press release we are not disclosing the zone nor the exact location because we do have some follow up work to do there, they have to capture some more land and set up some more drilling out there. So we are very excited about that 8 million at (inaudible). And we will need to get back on production later in December and watched out for a little bit to see the exact production performance but we are very excited about that and on seismic we do see some follow-up locations there will be more of that in the first quarter.
So with that, I would like to wrap up by saying that we're very pleased with the progress through third quarter, our operating and financial results were very solid and on budget. We look forward to a very solid Q4, weather has affected us slightly, but I think we are hoping to make up some lost time with some production expectations that may exceed our budget that will ready to be seen. But, we are on track to meet our exit targets in terms of production which sets us up very nicely for 2011.
So with that, I would like to thank you for joining us and I will open it for questions.
Thank you. We will now take questions from the telephone lines. (Operators Instructions). First question is from Brian Kristjansen from Canaccord Genuity. Please go ahead.
Brian Kristjansen - Canaccord Genuity
On the exploration success, I know you mentioned you want to build your position, but what do you have for follow-up currently and how big do you see your ability to expand that?
The existing land position that we own out there is about a 11 sections net to us. It's very close to our existing infrastructure, so we can get the well tied in fairly quickly. There is other lands available, we will be acquiring additional 3D sized to help them [innate] and follow this play up. It is not a new play for us. It exists in both Hythe and Bigstone, so that we are using our existing expertise to pursue this. So there is at least four step-outs without moving to a down spacing phase on this, so we do see, do see it has some aerial extent to it.
Brian Kristjansen - Canaccord Genuity
Can you talk at all about your follow up, I imagine, you've done a number vertical re-completions or reentries for the second light things? Anything new to talk about there?
We have on the second light that’s a shale oil play and Bigstone and of course we have had our vertical well producing since spring un-stimulated and we did pump a fairly large water base frac into that. We continue to slow that back and produce that back on clean-up. I would say the results to date are still a little inconclusive but we have not materially impacted the production rate at this point in time, but having said that we still have some a fair load water to get back. We have perforated two other existing well bores and had minimal inflow, so once we see the results of this first frac, we will then be refining our frac program and maybe even fluid type before we move on to the second and third frac.
It is progressing that slower than we had originally planned largely because we had a partner, we had to wait on to get approval to frac this first producing well.
(Operator Instructions). The next question is from Ray Kwan from Macquarie. Please go ahead.
Ray Kwan - Macquarie
I just have two quick questions actually, one is on your Cardium, in terms of completion and completion recipe going forward, it looks like you guys are growing longer laterals as well as more fracs. So are you guys going to keep it to that level or are you going to potentially go further in terms of links as well as the number of fracs there. And I guess the second question I have is more on the Duvernay In the Sturgeon Lake area, I am just wondering in terms of timing, when do you think you are going to put down this stratographic test over the well there? Thanks.
First on the Cardium in Bigstone. The cast to go little bit longer and add a number of fracs tighten up that spacing. We really will look to production performance to try and figure out whether we are heading in the right direction or not in terms of the number of fracs in that frac spacing. We are encouraged with initial results but a little time will tell.
From a perspective of ability to drill extended length horizontals, not all of them will be able to go out 1,300 meters. So we will see in certain cases, 700, 800 meter wells and in other cases, 1,300, 1,400, but I think in general our technical guys are feeling that the frac spacing that we have tightened up to will help. Productivity and ultimate recoveries but time will tell. We continue to believe that the oil based fluid is the way to go and we try and recycle as much of that as possible because it is fairly expensive.
Ray Kwan - Macquarie
And do you think costs are going to be around this 3.8 million still?
Costs with these increased number of fracs, I think these two wells came in more like about 5 to 5.2 million, now that had the frac fluid fully built into that without any re-cycling charge. So that will come down slightly, but those were more expensive to drill and complete. As far as the Duvernay we are getting to the point where we are seeing some final data come in working to oil and place number, some permeability numbers and then ultimately some sort of economic model that we can start to run.
So a lot of the science work that we done on core and samples is nearing completion we haven’t put a strap test into the capital program for the winter program. We are just not quite ready yet, I suspect it would be summer or later next year that we would move on that, unless we see industry moving in that direction little quicker. I would sure like to see a larger player in there drilling in the oil window prior to us moving in there.
Thank you there are no further questions registered at this time I would now like to return the meeting over to Mr. Reid.
Well thank you. I would like to thank everybody for joining us today. I know it is a busy time with reporting season, but thank you for taking the time to listen in to our conference call and should you have any questions you can contact myself or Brian directly we’d be happy to talk to you and answer any other queries that you may have. So thanks again and have a great day.
Thank you the conference has now ended please disconnect your lines at this time. We thank you for your participation.
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