Ranger Oil Corp (ROCC) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation third quarter 2011 earnings conference call. As a reminder, today's call is being recorded. At this time, it is my pleasure to turn the call over to your host, Mr. BairdWhitehead, President and CEO. Please go ahead, sir.

Thank you, Leah. Good morning and welcome to Penn Virginia's third quarter 2011conference call. I'm joined today by various members of the Penn Virginia team, which includes Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO; Jim Dean, our Vice-President of Corporate Development; and John Brooks, our Vice President and Regional Manager of our Houston office. Prior to getting started, we would like to remind you of the language in our forward-looking statement section of the press release that we issued last night and the Form 10-Q that will be filed later today which will apply to our comments this morning.

We would like to begin our discussion by expanding on the earnings and operational update press release that was issued after the close yesterday. First of all, we had an improved financial and operational quarter with revenue, EBITDAX, cash flows, and adjusted earnings per share that were much better than the previous year's quarter, as well as beating Wall Street expectations, due primarily to our significant growth in our oil and liquids production, which in turn is attributable to the strong results to date in our Eagle Ford Shale drilling program.

Product revenues of $82 million were up 20% over the third quarter 2010 and up 12% sequentially from the second quarter of 2011. Oil and liquids revenues of $47.8 million were up 129% over the third quarter 2010 and up 38% from the second quarter of 2011. EBITDAX of $65.7 million was up 43% over the third quarter 2010 and up 38% sequentially from the second quarter of 2011. This improvement in EBITDAX was attributable to not only the increase in oil and liquids revenues, but also to our focus on our direct operating expenses which decreased from $2.14 per Mcfe from $2.25 in the third quarter of 2010 and $2.47 per Mcfe in the second quarter of this year.

We continue to emphasize driving our cost down. It has been done through the sale of some higher cost assets and overall focus on lowering our controllable costs in our fields, including a reduction in compression expenses and also going forward with the consolidation of our Mid-Continent operations into our Houston office together with related reduction in staffing. Our cash operating margin defined as product revenues less direct cash operating expenses increased 63% to $4.72 per Mcfe from $2.80 per Mcfe in the third quarter of 2010, again due to our strategic shift towards oil and natural gas liquids, as well as our cost-cutting focus.

Adjusted earnings was a loss of $6.7 million and adjusted earnings per share was a negative $0.15, which includes a cash impact of derivatives and excludes charges for restructuring costs, the loss on the extinguishment of debt, and other nonrecurring items. This is an improvement of $0.16 over the third quarter of 2010 and improvement of $0.11 over the second quarter of 2011, due primarily to the increase in our cash operating margin associated again with this transition to liquids.

Production was 11.9 Bcfe or almost 130 million a day equivalent, which was 10% below the third quarter 2010 due primarily to 26% less natural gas production since we purposefully had elected not to drill gas wells in essentially the past 12 months. In fact, gas decline was more than offset in value by a 63% increase in oil and liquids production from 399,000 barrels in the third quarter of 2010 to 649,000 barrels in the third quarter of 2011.

Third quarter production 33% oil and liquids, as compared to 18% in the third quarter 2010 and 24% in the second quarter of this year, so you can see that that ever increasing percent of our total production comes from the liquids. And we expect oil and natural gas liquid production to increase further in the fourth quarter to 42% to 44% of our total production. This significant increase in liquids provides financial benefits and revenues and margins, which we believe outweigh the year-over-year production decline as we continue to transition to an oilier portfolio.

In the press release, we have given you a very detailed update of our total Eagle Ford program that we have drilled to date. We have drilled 24 wells to date, 20 of which are online. The other four are either waiting on completion or are in the process of being completed. The 20 wells online reflect an average peak rate of approximately 1,000 barrels a day equivalent, with an average 30 day rate of almost 700 barrels a day equivalent for the wells for which we have that information. We have averaged lateral lengths of about 4,000 feet with 16 frac stages. Going forward, we expect our well costs to average about $8 million for this type of well, which results in a rate of return of approximately 40% and a present value discounted at 10% of approximately $5 million per well, which assumes a 100% working interest.

This also assumes an approximate 450,000 barrel equivalent reserve-type well, which we feel is the average well we have drilled to date on our acreage. Production has averaged about 90% at the well head with 10% wet gas being processed with the yield of 145 barrels of natural gas liquids per million cubic feet of gas. We expect now to TD 33 Eagle Ford wells by the end of the year, temporarily using four rigs, going to three rigs as the quarter progresses. And as you would expect, we will be very active completing wells in the fourth quarter this year and into the first quarter of 2012.

We are now drilling our first three-well pad with all three wells being drilled in the same down-dip direction. The only disadvantage of this, of course, is in order to complete the three wells or initiate completion, we have to get the three wells drilled. The second of these three wells on this pad is currently being drilled. This will also be our initial attempt to drill wells on a shallower space than our typical 1,200 foot space in between laterals. At the toe on this three well pad, the spacing will be approximately 1,200 feet, but as you approach the heel and come back toward the vertical section of the wells, the spacing will approach about 600 feet. And ultimately, we think we will end up drilling many of our wells on the shallower with spacing.

Due primarily to higher to higher proppant costs and overall cost increases with our Eagle Ford completions, our well costs now have increased to what we would expect to be approximately $8 million per well going forward. This is part of the reason why we've had to adjust our capital guidance for the year. As the year progresses and, too, into next year, we will continue to make adjustments to our completion design by decreasing the frac interval length or, in other words, increasing the number of frac stages, not only with an attempt to improve upon our well results but at the same time, we're going to tweak the overall types of proppants we are using to reduce our well costs.

We have also finished up with our data acquisition of our 3D seismic survey over our acreage and have initiated various forms of processing. This ultimately would help in the placement of our laterals in the Eagle Ford and will help us analyze the potential of drilling laterally in the Austin Chalk. Even though we have not yet picked an Austin Chalk location, based on very good mud log shows while drilling and the evidence of natural fractures within the Chalk itself, ultimately we will drill a horizontal well in the Chalk in order to test its potential.

As pointed out in the press release, we acquired approximately 2,000 net acres in the Eagle Ford in the third quarter of this year, bringing our total to about 15,000 net acres or approximately 18,000 gross acres. Acreage costs remain high and sellers' expectations are often times much higher than we can economically justify. But while we still want to get to our stated goal of 25,000 net acres, it likely will not happen by the end of this year as I originally anticipated. So we have time to pursue new opportunities and have more than enough inventory of undrilled locations in the Eagle Ford to keep us busy for at least the next two years. I still think we can achieve this goal even though admittedly it we will carry over into 2012.

We remain committed to retaining a strong and flexible balance sheet with ample liquidity to position us to weather challenges or take advantage of market opportunities. We have taken a number of steps in the recent months to shore up our liquidity, which Steve will update you on, including a new credit facility with more are accommodating leverage covenants over the next five years and the sale of non-core gassy properties. We will continue to consider additional asset sales not necessarily to just fund our future capital expenditures, but more precisely to supplement future cash flows and ultimately increase the borrowing base associated with our acceleration of growth in our oil and liquids production.

So with that, I would like to turn it over to Steve to have him give you an update of our financial progress for the quarter. Thank you, Baird. Good morning. I will continue to follow the general outline of the release starting with the third quarter financial results on page two. The review will generally be comparing our third quarter 2011 results with our prior year quarter results, unless otherwise stated.

Starting with financial results, as Baird already described, our product revenue, adjusted EBITDAX, cash flow, and adjusted earnings per share were stronger in the third quarter both year-over-year and sequentially compared to the second quarter, driven primarily by our growth in oil and NGL revenues and our stronger gross cash operating margins.

In fact, our $65.7 million adjusted EBITDAX for the quarter, which is reconciled on page nine of the release, was the highest level we had achieved since 2008. We reported a $9 million operating loss for the quarter, which is a $44.1 million improvement over the prior year quarter. This improvement was primarily due to higher oil and NGL revenue, lower direct operating expenses, lower exploration expense, and a $35.1 million decrease in impairment expense, offset by lower natural gas revenue and higher DD&A expense. I'll be describing each of these components in more detail.

Production was lower this quarter, as Baird mentioned, compared to the prior year quarter, but it was up sequentially over the second quarter from 11.7 Bcfe to 11.9 Bcfe. Pro forma for our recent Arkoma asset divestiture that was completed and announced on August 31st, production was down 7% year-over-year and up 4% sequentially. Production was impacted during the quarter by completion delays, some shut-ins related to East Texas brush fires, and lower NGL recoveries due to a fire at a third-party downstream processing plant in the Mid-Continent.

But what's important to note in our production number is our increase in oil and NGL production. Our oil and NGL production is up 63% year-over-year and up 38% over the second quarter. As Barrett mentioned, our gross cash operating margin is up. Our cash margin in the third quarter was $4.72 per Mcfe, and that compares favorably to $2.89 per Mcfe in the prior year quarter, also a 63% improvement. This improvement to our margin combined with the increase in oil and NGL production is what really is driving our financial results this quarter.

Our realized oil price for the quarter was $87.03 per barrel, 23% higher than the prior year quarter and 12% lower than the second quarter of this year. Our realized NGL price was $48 per barrel for the quarter, and this was the first full quarter where we realized the benefit of processing our Eagle Ford Shale gas though NGL revenue was a significant contributor to this quarter's financial results even with the temporary lower processing recoveries due to the processing plant fire. Our realized natural gas price was $4.24 per MMBtu, 3% lower than the prior year quarter, and 2% lower than the second quarter of this year.

Considering the effects of hedges, our realized oil price was $88.28 and our realized natural gas price was $4.87. Our operating expenses were generally lower across the board as detailed in the release. On a per Mcfe basis, our direct cash operating expenses were $2.14, as compared to $2.25 in the prior year quarter, and $2.47 last quarter, a significant improvement. G&A expense is worth noting. We realized a $1.7 million reduction in recurring G&A during the quarter due to the effects of closing our Mid-Continent office in Tulsa and selling the Arkoma assets. This is offset by an $800,000 one-time restructuring charge related to the headcount reduction, and we expect to have a fourth quarter charge related to the office closure when we vacate the space.

Exploration expense decreased by $2.7 million to $19.3 million, primarily due to the fact that we incurred a $9.3 million dry hole cost in the third quarter of 2010. Our G&G costs were also $1.2 million less this quarter, offset by higher lease amortization and a $4.8 million one-time charge related to the temporary suspension of drilling in the Marcellus. DD&A rate increased to $3.80 per Mcfe from $2.50 in the prior quarter, primarily due to the higher cost on a unit basis for the Eagle Ford wells. And as I will discuss in a minute, DD&A per Mcfe will increase in the fourth quarter and beyond due to the focus on the higher F&D but higher return Eagle Ford Shale.

Overall, we reported a net loss of $6.7 million or a $0.15 per diluted share for the quarter. This compares favorably to the $30.2 million or $0.66 per diluted share loss in the prior year quarter. The improvement is due primarily to our improved operating margin and lower impairment expense, offset by slightly higher interest expense, a $1.2 million loss on extinguishment of debt related to the credit facility refinancing, lower derivatives income, and a lower income tax benefit. Our capital expenditures for the quarter were $114 million, down from $147 million in the prior year quarter, and up from $105 million in the second quarter of this year. About 90% of our CapEx was spent on drilling and completion activities primarily in the Eagle Ford Shale. As I will discuss in a minute, we expect fourth quarter capital expenditures to be similar to the third quarter.

Moving on to capital resources and liquidity. At quarter end, we had total debt outstanding of $620 million consisting of $600 million of senior unsecured notes, $5 million of convertible senior subordinated notes, and $15 million drawn on the credit facility. Our credit facility was refinanced during the quarter with a five-year maturity due in 2016, as was discussed on the second quarter earnings call. With that refinancing complete, we now have no material debt maturities until 2016.

Our borrowing base was recently reaffirmed by 100% of our bank group at $380 million, which includes the effects of the Arkoma asset sale. We have elected to maintain our $300 million commitment for now, but we have an accordion feature that allows us to take the commitment up to the borrowing base at our election assuming participation by one or more of our banks. Total liquidity under the credit facility at quarter end at our current commitment level was $284 million. Assuming access to the full borrowing base, total liquidity increases to $364 million.

A quick note on hedging. Our weighted average hedge position shown by quarter is summarized on the last page of the release. We entered into two oil collars during the quarter. For 2012, we entered into a $90 by $97 collar on 1,000 barrels per day. In 2013, we entered into a $90 by $100 collar, also on 1,000 barrels per day. There will be a premium due for each of these trades. We'll pay $7.63 per barrel on the 2012 collar and $9.87 per barrel on the 2013 collar. The premiums owed will be paid on a monthly basis as part of the monthly cash settlement.

We also restructured the existing $100 by $120 costless collar on 500 barrels per day in 2012 to be a $100 swap. The premium we earned in the restructuring of this collar will be paid to us monthly, and the $7.63 per barrel premium I mentioned for the 2012 collar is already net of the premium we will receive for restructuring the swap. There have been no new gas hedges during the quarter. Using the midpoint of guidance, we currently have 38% of our natural gas price exposure and 26% of our overall commodity price exposure hedged for the fourth quarter of 2011.

Moving on to the guidance discussion on page ten of the release. Our production guidance for the full year is 48 to 48.5 Bcfe, which implies guidance for fourth quarter production of 12.2 to 12.7 Bcfe. This volume range implies a 3% to 7% sequential increase over our third quarter production. We expect NGL processing for Eagle Ford gas will resume to full recoveries later this month. Oil guidance is being tightened within the range provided last quarter and implies a 50% to 62% increase over the third quarter, the timing for completions, especially as we start drilling multiple wells per pad, is the biggest variable in oil production as Baird already discussed.

NGL guidance is being lowered due to the continued blending and bypassing of gas from the Eagle Ford at the damaged processing plant during repairs, and we expect the plant to be operational sometime this month. Natural gas guidance was lower due to uncertainty around some of the non-operated Granite Wash completions in addition to natural declines. Operating expenses, exploration expense, and recurring G&A are generally expected to be in line with third quarter results. We are allowing a $600,000 to $800,000 restructuring cost due to closing of the Mid-Continent office as I already mentioned.

DD&A is increasing $4.67 to $4.86 per Mcfe due to the higher F&D costs associated with the Eagle Ford wells, which is where we're investing primarily all of our money. And finally, we are raising our capital expenditure guidance to a range of $433 million to $443 million, which implies fourth quarter spending of $110 million to $120 million in line with our third quarter spending. Spending has increased in the second half of the year primarily due to higher completion costs for the Eagle Ford wells as Baird already alluded to.

With that, Baird, that concludes guidance.

Thank you, Steve. Lastly, before we open things up for questions, we've intentionally not mentioned anything about 2012 guidance at this time. We are still finalizing our plans for the year and we will announce those plans when appropriate. But it is reasonable to expect the majority of our next year's spending, as with this year, of course, will be comprised of drilling in the Eagle Ford and to a lesser extent in the Granite Wash. The one thing we are evaluating is reinitiating the drilling of horizontal wells in the Cotton Valley.

This is based on not only because of the high liquid component associated with it, but also as we continue to gather longer term production information from the wells that we drilled in 2010, we think that we can reinitiate that program with very acceptable returns. In addition, we are still deciding how many exploratory wells to drill, not only in the Marcellus, which we'll test our eastern portion of our acreage in Potter and Tioga county, but we also have a number of prospects in the mid-continent and we still think even though we drilled some unsuccessful wells there in late 2010 and early 2011, we still think we have some good prospects teed up to drill. But having said all this, we do expect to spend less in 2012 than in 2011 and, at the same time, expect growth in production. But more importantly because of the liquid side of things, a more significant increase in cash flow next year.

And with that, Leah, I would like to open things up for questions, please.

Absolutely. Ladies and gentlemen, today's question-and-answer session will be conducted electronically. (Operator Instructions). And we'll move first with Neal Dingmann from SunTrust.

Hi, this is Joanna actually for Neal. I was wondering if you guys could just talk about the pace of drilling that you need to take in the Eagle Ford just to hold acreage?

John Brooks, our Regional Manager in Houston, John, can you answer that, please?

Yes, we've got substantially most of the acreage held right now, so the exploration calendar isn't really driving the drilling schedule. That being said, we should be able to HBP the majority of the acreage in 2012.

Okay. And then can you just give us a little bit more color about the variability of results you had in the Eagle Ford for your last 20 well results and I guess just some of the lower results you have had more recently?

Yeah, typically, it has been the result of whether we drill up-dip or down-dip. As you drill up-dip and you get closer to the oilier or shallower part in the oil window, they tend to be lesser result kind of wells. As you drill down-dip and the wells are some what gassier, they tend to be our better wells. We have also seen, which we expect is some natural fracture component that has helped us not only in the Eagle Ford, but in some cases we think we are talking to the Austin Chalk also, which has improved some results. So I realize we've had a range of wells, but this is a statistical play, you would expect to see that, and, again, if you take into consideration our average and our mean, there's still very, very high rate of return kind of wells.

Right. Okay. Lastly, can you just speak to just the service costs you are seeing and just expectations going forward? Baird Whitehead: John, why didn't you go ahead and answer that question, please.

Yes, we have got -- our drilling costs are fairly stabilized by the long-term contracts we have with HMB and our service costs on the completion side, at least on the pumping side, with C&J Services. What we have taken to doing here lately is obtaining our profit on more of a wholesale basis, which has driven those costs down and that is where we think we will have the biggest reduction in our completion costs going forward is buying the property basically on a wholesale basis as well as optimizing the frac designs a little further.

Thank you.

Thank you.

And we will move to our next caller from Wells Fitzpatrick with Johnson Wright.

Good morning.

Good morning, Wells.

Sorry if I missed it, but can you guys talk a little bit about the cost savings that you expect to see from the move to those three-well pads and how far you think you might be able to come off that $8 million?

Well, there will be some location costs efficiencies, there will be some mobilization efficiencies as far as moving the rig around since we will be parked right there. That will be the bulk of the efficiencies. Where we plan on trying to save money going forward, as John mentioned, we are going to spend more time on the completion side, we have secured proppants directly, which will save us some money. We also think, in some cases, we can reduce the amount of high strength proppant and go more with a mix of white sand and resin coated sand and in some cases because we do plan on attempting to reduce the lateral length between stages, reduce the overall size of the treatment itself. We think we are going to save the most money going forward is on the completion side.

Okay. And am I right in remembering that the last subject that C&J contract went out to mid-12. Is that still the case?

It does, but we have the right to renew it or extend it again for another year beyond that.

Okay. And as far as the three-rig program, do you think that that contract can satisfy that program or will you be looking for outside slots?

No, that three-rig program keeps that frac crew busy.

All right, perfect. That's all I have got. Thanks so much.

Thank you.

(Operator Instructions). Next we will hear from Steve Berman with Pritchard Capital Partners.

Good morning, guys.

Hi, Steve.

The $8 million well cost you cited earlier in your talk, is that a normalized level or is that the cost that's built into your higher CapEx number for Q4?

That is a number that we feel going forward that we can drill wells for now. We have drilled some higher priced wells in the front end of this year for various reasons. Learning curve issues, there were some pilot holes that we drilled to gather some vertical information at the Eagle Ford and Austin Chalk itself, there was a full core that we had actually taken in the Eagle Ford and chalk in the Austin Chalk and the Buda. So we had some loaded costs higher than $8 million per well in the earlier part of the year, but a lot of this stuff, size kind of stuff is behind us and we expect the $8 million cost to be more representative of what we will drill going forward.

But the $8 million cost must have been higher from the previous CapEx guidance you were giving.

It was. It was.

And in terms of some completion delays and things like that, I mean how quickly do you think you can get that behind you and get to whatever you consider a normal backlog?

Well, we think we are more on a routine basis now. I don't know how many wells we are fracking this month. John, help me out there a bit. We will be able to keep C&J busy with three rigs for sure. And if we do resurrect the East Texas program, we have the ability to take that frac crew to East Texas.

In terms of point, resurrecting the horizontal Cotton Valley program, on an earlier call, and I don't follow (inaudible), but someone mentioned that they've seen a 20% decline in the Haynesville well costs, which I assume that's in East Texas. If that's true, is that something for you to look at to maybe reconsider going back in there sooner than later?

Steve, it is not in the cards right now. We -- if you look at in our investor presentations, and if you look at the longer term production information of those five Haynesville wells we drilled, we feel comfortable with the 6.5 to 7 Bcf kind of number. Those wells probably average $10 million to $11 million per well because of the increased number of frac stages that we had undertaken in those wells, which were directly correlated with the improved results. Now, if we can take 20% off that and get those well costs down to $8 million or $9 million, you really have to spend more time looking at it.

At this point in time, you know, with $3.80 or $3.70 gas price, it probably doesn't make sense to do that. Most of the acreage is sale by production. It is not going anyplace. But having said all that, with a 450 gas price flat, $4.00 to $4.50, and a $9 million well cost, the returns of those wells are probably 20% to 25% after tax. So it stays in front of us and we look at it continually, but at this point in time, we would resurrect the Cotton Valley before we resurrect the Haynesville.

Perfect. That's it for me. Thanks, Baird.

All right. Thank you, Steve.

Our final question comes from David Snow with Energy Equities.

Hi, did you give (inaudible) for your Eagle Ford wells?

David, yeah, it was -- we are using about 450,000 barrels right now, and that's based on the wells we have drilled to date and how they have performed. There are some wells out there, some of the better wells will probably be 600,000 to 700,000, some of the lesser wells will be a few hundred thousand, but that 450,000 is a good average right now.

And can could you give a breakdown approximately of what you are producing in oil, NGLs, and natural gas in the Eagle Ford?

John, do you have a -- it sort of moves all over place depending on completion activity, but do you have a good average, recent average?

Yeah, the oil is producing between 6,000 and 7,000 barrels per day, that's on a gross basis, and our gas sales around 4,000 Mcf a day. And on that 4,000 Mcf, that is going to be around 140 to 145 barrels per million of NGL yield with about a 27% shrink. I know there are some calculations that have to go through that. But it is primarily going to be driven by the oil which is, like I said, right now we are making between 6,000 and 7,000 barrels a day and a gross field-wide basis.

Okay, thank you very much.

Thank you, David.

And there are no further questions at this time. I will now turn the call back over to the speakers for any additional or closing remarks.

Thank you, Leah. I appreciate you listening in. I think we are on the right path. I know that it has been somewhat painful, but I think we have turned a corner of our focus on oil and the results of the Eagle Ford program, and I do think over time we are going to be able to add acreage. We do not want to add acreage at $15,000 to $20,000 an acre, but if we continue to plug along and pick acreage up anywhere from $2,000 to $10,000 an acre, which will still yield very acceptable returns, I think over the long-term, we've got more than enough time to replenish our inventory and expand our inventory in the Eagle Ford, and, again, we're on the right path. So again, thank you very much.

Thank you, ladies and gentlemen. That does conclude today's program. We appreciate your attendance. You may now disconnect.