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Executives

David Reid - President and CEO

Brian Kohlhammer - VP Finance and CFO

Analysts

Brian Kristjansen - Canaccord Genuity

Kurt Molnar - Stifel Financial

Delphi Energy Corp. (OTCPK:DPGYF) Q2 2010 Earnings Call July 29, 2010 11:00 AM ET

Operator

Welcome to the Delphi Energy Corp. 2010 second 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 Corp.

David Reid

Good morning everyone and welcome to our second quarter 2010 conference call. As mentioned, I am David Reid and I'm the President and CEO. I am joined today by Brian today by Brian Kohlhammer. He is our VP Finance and CFO.

We'll start the call with some general remarks on the company's progress, followed by some comments on the second quarter and the current gas price environment and provide some discussion around the outlook over the remainder of 2010, especially our capital program that we outlined in the press release. And finally, we'll open up the call to your questions.

Firstly, as always, please 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 in the MD&A attached to today's press release to inform you that this disclaimer applies to any forward-looking information disclosed in today's call.

Firstly, just a little bit of background on Delphi for those of you that are unfamiliar with us. We're predominantly a natural gas E&P company. In second quarter, we were 80% natural gas by production, with over 95% of our production reserves and 95% of our undeveloped land located in the deeper areas of the basin in northwest Alberta and into northeast British Columbia. We operate approximately 85% of our production and constantly operate about 95% of our field capital programs.

We view what was a very quiet second quarter as very positive on a number of fronts. From an operations perspective, the production performance from our Q1 drilling program has been very positive. In the press release, we've outlined the 60 and 90-day production performance of a number of our projects we did in the first quarter and are very pleased with those results and that performance.

Especially with regards to the horizontal wells drilled in the Cardium, which are outperforming a great number of the Cardium wells that have been drilled and have that kind of production history, as well as our Doe Creek light oil plant at Hythe is performing very, very well as is our Falher horizontal gas well and our Bluesky at Hythe.

The Q1 drilling success at Wapiti in the Nikanassin and Bluesky did prompt us to construct in the second quarter here a 15-kilometer $3 million pipeline, 100% owned by Delphi, that connects us more directly to the Deep Cut facility of Devon's, which we also have a working interest in.

Now, this pipeline will increase our total infrastructure takeaway capacity from the area to over 20 million a day with an average NGL content of about 18 barrels per million or in total about 5,000 BOEs a day, setting us up for a continued unimpeded growth like we've been delivering at Bigstone and Hythe. So we're very, very excited about the results that we've had in Wapiti.

And this positive performance gives us the confidence to continue to develop and move forward everything that was successful in the winter program, and that's reflected in the second half drilling program we've outlined. And we have a much greater confidence level in advancing a number of these scalable growth-oriented project types on the horizontal drilling front.

From a financial perspective, Brian will get into much more detail, but I'm very pleased with the strong cash flows, especially on a per unit base, despite AECO being $4 in the quarter. And part of that was certainly due in part to increasing oil and NGL component, but also our strong production.

Our operating cost reductions continue to play an important role in being efficient and economic in this environment. We saw our royalty rates increase slightly, but that's really due to our increased oil and NGL production. And Brian will talk more on that.

We continue to benefit from the strong hedge position, and we'll beat AECO again this time by 36%. So that continues to play a strong role in our financial strategies as well continuing to pursue greater components of oil and NGL in our mix.

So we remain very optimistic and confident in our ability to execute in what continues to be a challenging environment from a gas pricing perspective, but things are going very, very well.

So with that, I'll turn it over to Brian and he will provide some comments around the financials, and then I'll come back and talk about the second half capital program.

Brian Kohlhammer

Thanks, Dave, and good morning, everyone. From a financial perspective, we're focused on two primary objectives. One is maintaining our strong financial position, our balance sheet, with the strong position we've got there, and also having a recycle ratio of at least 2-to-1.

As we've talked about before, we're focused on generating an operating netback recycle ratio of approximately 2.4-to-1 and a cash netback recycle ratio of about 2-to-1. Generating recycle ratio of greater than 2-to-1 will provide us with the cash reserves to pursue our planned capital program to grow production and reserves and add considerable value to the company for our shareholders. At a minimum, we strive to achieve a cash netback of at least $20 per boe and planning and development cost of $10 or less for two key reserve additions.

In light of the low natural gas price environment we are in, and may be in for a while, operating efficiencies are critical in generating this recycle ratio. From a perspective of generating a cash netback of at least $20 per boe, as a significant natural gas producer in this commodity price environment, we are encouraged by the positive results we see in our production volumes, particularly the change in our production mix, our realized sales prices and decreasing operating costs.

In the second quarter of 2010, we increased our oil and NGL production by 86% compared to the same quarter last year. Liquids production represented 20% of the company's production in the second quarter. However, it was 41% of the revenues earned, excluding hedges.

We expect the liquids portion volumes to grow in future quarters, as production from liquids-rich Wapiti/Gold Creek area comes on stream, and the capital program for the remainder of the year is primarily focused on oil or high-end GL content opportunities.

By the end of 2010, we expect liquids to represent 23% to 25% of our daily production. A greater component of liquids is part of the production mix, which comes as significantly higher netbacks for natural gas at the moment will protect our cash flow towards funding of the 2010 and future capital programs.

Realized sales prices per boe is a key driver of cash netbacks. It is through the realized sales price that you can see the benefit of a growing liquids component of production. An increase in crude oil and liquids prices and the change in production mix resulted in our realized sales price increasing by $2.50 per boe, despite a $0.50 per mcf or $3 per boe decrease in our realized natural gas price compared to the prior year.

Delphi's realized sales price is supported by several other factors, including the premium to AECO for marketing, heating content and hedges where we received an added 36% or $1.42 per mcf to the price of AECO.

In reviewing a few research reports that have come out on us this morning, it appears that our royalty costs have come out higher than most expected. Royalties have certainly been one of the most difficult variables to forecast with all the numerous changes announced, the price volatility from quarter to quarter, particularly for gas, and the change in our production mix.

One of the significant changes from the first to second quarter of 2010 was the much lower royalty credits. In the second quarter, we received an adjustment to a component of our royalty credits, which increased our effective Crown royalty rate on gas production in the second quarter.

In addition, we have recorded higher royalty rates on our oil production in the second quarter as compared to the first quarter of 2010. On a go-forward basis, we believe our average royalty rate will be approximately 16% to 18% comprised of gross at approximately 4% and Crown royalties at 12% to 14%. Price and individual well productivity will certainly affect these variables.

Operating cost continued to show improvements largely due to the growth in production volumes and our very cost efficient core areas of Bigstone, Hythe and Wapiti/Gold Creek. These three properties represent 80% of second quarter production, and operated at average weighted cost of $6.10 per boe.

In the second quarter of 2010, operating costs were down 8% from the first quarter and down 20% from the comparative period of last year. In 2010, we anticipate operating costs being in the $7.75 per boe to $8.25 per boe range for the year as we focus in these three main core areas where we have ownership and the necessary gathering and processing facilities.

On a quarter-by-quarter basis, we believe we will continue to see further operating cost reductions throughout 2010. In the third quarter and going forward, we will see the benefit of the disposition of our high cost East Central Alberta properties. Based on the operating costs for the first six months of the year, this disposition should reduce our corporate operating costs by $0.35 per boe to $0.40 per boe on a go-forward basis.

Other initiatives are also being reviewed to further reduce our operating costs.

In the second quarter this year, our G&A costs were increased by a one-time bad debt expense related to a joint venture dispute. This had the effect of increasing G&A by about $278,000 or approximately $0.38 per boe in the quarter. Excluding this charge, results in a G&A per boe number, more in line with our full year expectations of $2 per boe.

In addition, the quarter included compensation adjustments for the staff. Delphi staff complement is now in place to grow production for several years. As production increases, we would expect the cash cost per boe for G&A and interest expense to come down also relative to prior years.

As we focus our capital program in our core areas and grow our production, we anticipate our controllable cash costs will continue to decrease. Royalties will fluctuate with commodity prices and well productivity.

We continue to remain in a strong position with the debt to cash flow ratio of 1.4:1 based on an annualized first six month cash flow of $28.1 million. We utilized our available credit capacity to execute a first quarter capital program greater than the total field capital program in 2009 and then reduced our net debt as planned through the second quarter.

Net debt at the end of June was $79.2 million, and this includes the proceeds from our equity offering. With this strong financial position, we have commenced an expanded capital program for the second half of the year, which is expected to grow production to 9,000 boe a day with net debt at the end of the year at approximately $100 million.

Lastly, I would just like to touch on our market guidance for 2010. We mentioned that we were lowering our cash flow expectations to $57 million to $62 million from $60 million to $65 million for the year. We do not see this as a big change, but we thought it was appropriate to revise our natural gas prices forecast for the remainder of the year. Our new guidance is based on an AECO gas price of approximately $410 per mcf.

Dave, I'll pass it back to you.

David Reid

Thanks, Brian. So with very little field activity in Q2, I'll of course just focus on the second half capital program and our drilling plans that we outlined in the press release. As Brian mentioned, the second half capital program will total about $50 million to $55 million and as outlined we are going to drill about 17 gross well across our three core areas. And this would bring our full year 2010 CapEx to about $90 million to $100 million up from what we previously stated of $80 million to $90 million. But that's still within the context of our expected cash flow through the second half of the year and the equity proceeds that we had taken in earlier in the quarter. But this capital program does have some moving parts, and I'll just speak to a couple of them.

We have increased our land acquisition spending through the second half, allocating an additional $2 million to capture additional Crown lands within our core areas. There is no guarantee we will spend that money. We've also allocated an additional $1.5 million advance our light oil shale project with most of that going into the recompletion projects in the Second White Specks at Bigstone.

The other moving part is fairly significant as we are planning to expand the processing plant within our Hythe property, alternatively acquire an additional interest in that plant in preparation to handle the significant growth beyond what we see in the next 12 months looking light. Keep in mind, Hythe has grown from 400 BOEs a day to currently 3,000 BOEs a day in about two years.

So the $7.5 million that we do have in this capital program that's allocated to this project may or may not be fully spent this year. And we've also allocated somewhere between $6 million and $7 million for late Q4 with the plan of getting an early start to our 2011 winter program with the objective of staying ahead of the winter rush on services, especially what we would see a potential bottleneck in the pumping and fracking services.

So there are some moving parts to this program, but it's a very well defined from a drilling perspective. So as far as the drilling program goes, it's very similar to the winter program where we drilled 16 gross wells achieving our objectives around our production growth targets and increasing our light oil and NGL mix. And ultimately de-risking advancing and advancing the multiple horizontal development projects that do have significant scale and repeatability for their company.

With respect to the ongoing drilling program and by design we're again taking basket approach to the plan with the luxury of multiple economic projects to choose from to again mix the light oil and natural gas with varying NGL content. And over half of it this time is going to be horizontals above 55% on a net well basis.

As we initiated the program post-breakup, we've had some minor weather delays. But otherwise, we've had a really good start to the program and hasn't been had much of an impact on us. We currently have five rigs active, three in Hythe and one in each of Wapiti and Bigstone.

I'll just comment on the status on some of our operations. For the most part, drilling has had a good start, we really haven't got going on much of our completions yet, but most of it status around our drilling. We have one vertical well drilled and cased at Bigstone. It was an earning well on a farm-in. We drilled it to the gas, but our primary objective was to capture more Cardium acreage in the area and that has been achieved and we will likely do a completion in that Cardium zone in the month of August.

We have also drilled and cased a vertical well at Wapiti targeting of course our primary being the Nikanassin as well as some other zones. And the completion operations there are being planned for mid-August. We do have one horizontal. Doe Creek has been drilled and cased. Fracking is scheduled for next week. We also have one horizontal Bluesky in Hythe drilled and we have placed our 12 fracs that is up from the seven fracs that we placed on the first horizontal Bluesky well. And those completion operations are ongoing, we've just placed those fracs and we will be following on clean up and evaluating over the next several weeks.

We also have a rig drilling a second Doe Creek well and we've just reached TD over night there, so we'll be finishing that up in the next several days and moving to completion operations in August as well. And our first Falher horizontal with yet another rig also has reached TD in the last 24 hours, and we will be finishing that up here shortly and moving to completion operations again over the next several weeks.

We have a second Falher horizontal that has just started drilling with a separate rig. And that's just spud. And our first Cardium horizontal in Bigstone, that rig is on the move, and we should be sliding within the next 24 hours. Just with respect to the Cardium at Bigstone, we've had some excellent production performance from the horizontals that we did drill this past winter as evidenced by the 60-day and 90-day numbers. And comparing that to some of the performance to the south of us, we're very pleased with those results. The results have been so good that our much larger partners and Talisman are now getting into the game.

And in the winter we farmed in on Talisman and they are now participating in this round of drilling. And as well, Conoco is now full steam ahead on plans to drill three horizontal wells this fall from a single pad, with ultimately 10 to 12 wells identified on that lower interest land block that we have with them on the (service) side of Bigstone.

So they will be operating that program. We will be operating to the North where we have a 55% interest on the land. So I think it's a good confidence boost for us that some of these other players are getting in on the act in the immediate area and contributing to moving the play forward.

With respect to the Second White Speck at Bigstone, we are in the field conducting two additional re-completions on two existing well-bores with the goal of delineating the areal extent of the play. We have a number of existing well-bores that we can re-enter from a vertical perspective and move to and better understand the reservoir characteristics and optimize our frac programs prior to what we would see, drilling a horizontal well tentatively planned for this winter.

As far as the Duvernay shale lands that we acquired, we're doing a lot of lab work right now on existing core and samples to assist us in quantifying the reservoir and fluid characteristics.

And right now, as we stated in the press release, drilling is probably a year away, unless our analysis prompts a decision to accelerate, or we have industry players advancing the play around us. So that will be a 2011 project.

In terms of our horizontal casting at Bigstone, it isn't in this second half program simply because our first location does have some access restrictions, and that will happen later this fall heading into the winter. It could possibly be part of the accelerated early start to the winter program, but look for that probably November-December to get started.

In terms of our Nikanassin horizontal at Wapiti, we do have several locations identified. Will be a winter program, simply because we do want to finish this second half vertical program, gather additional data from a geotechnical and operational perspective, especially with fracing and frac fluids, and then we will be very likely moving to horizontal drilling through the winter.

So we're very active out in the field with a program that mirrors the first-half drilling program, and it's designed to meet the objectives that I laid out earlier. We have some, what I would see as some pretty aggressive production growth targets, and we're certainly moving to delivering meaningful per share growth from our production.

We're continuing to increase our Light Oil and NGL content, which is allowing our cash netbacks to remain very robust. And we continue to de-risk and advance these multiple horizontal development projects that has significant scale and repeatability for the company.

Brian did talk about our guidance for 2010, and then of course we have not changed that 7,900 to 8,200 average for the year, even though the capital went up slightly. As you heard, a lot of that capital is not directly related to production additions for this year, but it does set up a very strong Q4 and a pretty solid-looking 2011 for us.

We do expect Q3 production to be relatively flat to Q2 as a result of our summer maintenance scheduled outages, as well as the new on stream timing of the ongoing drilling.

Our Q4 guidance of 9,000 BOEs a day, we've risked our new production additions much greater than our realized success of the first-half drilling program. So we feel very comfortable with our technical assumptions that's gone into this forecast. As well, we've been very conservative on our on stream production dates for the new wells that we will be drilling. We've built in some weather delays as well as some service delays as we anticipate some real pressure on pumping services.

So just to wrap up, we're on track to meet or exceed our 2010 targets, and 2011 looks like it's going to be a very good year for us. And we really are set up to deliver some meaningful and repeatable per share growth. And also hope you take away an appreciation for the multiple growth platforms that we are successfully constructing, as we very quickly grow into the intermediate ranks here.

So with that, I would open the lines up to questions for Brian and myself, and hopefully answer them to your satisfaction.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question is from Brian Kristjansen from Canaccord Genuity.

Brian Kristjansen - Canaccord Genuity

David, at the end, you mentioned factoring in potential delays for fracs. Have you experienced any yet?

David Reid

We haven't experienced any delays yet. We're starting to book our completions. I think there are two things. One, there is a bit of a backlog from pre-spring breakup. And two, I think the amount of horizontal wells being drilled is only going to increase. The guidance we're getting is that we're going to see a lot of pressure and the earlier we get a jump on it, the better. No delays yet, but I anticipate it's going to be offering up some challenges.

Operator

The next question is from Kurt Molnar from Stifel Financial.

Kurt Molnar - Stifel Financial

Just a few of them for you. First and foremost, vis-à-vis historical reserve profiles that are booked in the engineering, certainly the curves that you're commenting on here for the course of 2010 have been very strong. Do you see some upside potential in that regard vis-à-vis revisions to booked reserves as of the end of 2009?

Second question ties around the new pipeline to the Deep Cut facility. Will completion of that project have some natural lift in your liquids content reported before any new wells, and does it have nay ramifications to new reserve bookings?

And then just third question, can you give any kind of guidance as to what you think the run rate op costs are when you're through your optimization of all your work that you're doing?

David Reid

The first question regarding our capital program and the success of the additions, most of the first of our order program was not in our engineering report. So this fall and coming into reporting season, we will have a lot of data to work with. We would expect to see an increased layer of proven undeveloped and FDC into the engineering report. So I think we're going to have a set up for a pretty good year on reserves.

The second question around Wapiti in the gas plant, we have been flowing most of our gas in a roundabout way through the Devon Deep Cut facility, but on a very restricted basis. So what this will allow us to do is open up some existing production, as we stated in the press release that one of the wells hasn't even been brought on production. So that will be turned on here in the next week or so. And we will get full benefit of that.

Ultimately, we do expect that that incremental capacity there will drive some pretty significant growth for us and realize full value on both the (quantity) we get there as well as some of the lighter ends on the NGLs that are in the system. So a very positive move for us, and we did it 100% to try and maintain control of that area.

The third question, I'll turn it over to Brian in terms of our op costs and run rate.

Brian Kohlhammer

From our Q2 number of just under $8, East Central, as I mentioned, $0.35 to $0.40. So that can get us down to $7.60, $7.65. The other initiatives that we are looking at are over time as new wells come on, often we will rent our compressors initially to determine what size of compressor we need for the given well or the area of the field. And then with a little production history, you can sort of tell whether that's the right size.

And what we are looking at is the purchase of some of those compressors and to effectively put those costs on to our balance sheet, but it will reduce our operating cost. There is a few million dollars contemplated in our forecast for some of those initiatives. But it will be something that's done over time, not all at once does that capital will take away from our drilling capital.

Operator

(Operator Instructions) There are no further questions registered for the moment. I would like to turn the meeting back over to Mr. Reid.

David Reid

I would like to take this opportunity to thank everybody. I've just mentioned that if we have an answer to your questions online and you wish to contact us, we are in today. Both Brian and I are heading out on vacation here for the next two weeks. So you probably have today to get hold of Brian and myself and answer any outstanding questions that you may have. Other than that, you may get hold of Mike Kaluza, our COO, if you have any questions that we are unable to answer in our vacations.

So again, thank you for attending the conference call, and have a great long weekend. Thank you.

Operator

Thank you. The conference has now ended. Please disconnect your lines at this time. We thank for your participation.

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Source: Delphi Energy Corp. Q2 2010 Earnings Call Transcript
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