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Resolute Energy Corporation (NYSE:REN)

Q3 2012 Earnings Call

November 5, 2012, 5:00 p.m. ET

Executives

Michael N. Stefanoudakis – SVP, General Counsel, Secretary

Nicholas J. Sutton – Chairman, CEO

Theodore Gazulis – EVP, CFO

Analysts

Don Freeman – Raymond James

Noel Parks – Ladenburg Thalmann & Co.

Richard Tullis – Capital One Southcoast, Inc.

Ronald Mills, Johnson Rice & Co.

Brian Ottman – Suntrust

Jason Wangler – Wunderlich Securities, Inc.

Operator

Good afternoon, my name is Rachel, and I will be your conference operator today. At this time, I would like to welcome everyone to the Resolute Energy’s Third Quarter Earnings 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).

Thank you. Michael Stefanoudakis, General Counsel, you may begin your conference.

Michael Stefanoudakis - SVP, General Counsel, Secretary

Good afternoon, everyone. My name is Michael Stefanoudakis, I’m the Senior Vice President and General Counsel of Resolute. I’d like to read the forward-looking statement before turning the call over to Nick Sutton, our Chairman and CEO.

This investor conference call includes forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expect, estimate, project, budget, forecast, anticipate, intend, plan, may, will, could, should, poised, believes, predicts, potential, continue and similar expressions are intended to identify such forward-looking statements.

Forward-looking statements in this conference call include matters that involve known and unknown risks, uncertainties and other factors that may cause actual results, levels of activity, performance or achievements to differ materially from results expressed or implied by this investor conference call. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this call.

At this time, I’d like to turn the call over to Nick Sutton, our Chairman and CEO.

Nicholas J. Sutton

Thank you, Michael. Good afternoon and welcome to Resolute’s third quarter 2012 earnings conference call. As we have done in previous calls, I will provide you with a brief overview of the Company and then an operations update. After that, Ted Gazulis, Resolutes Chief Financial Officer, will review our financial results, we then will take your questions.

I intend to keep my comments brief because I believe we covered most key points in our press release that crossed before the markets opened this morning.

First of all, I’m pleased to report that our third quarter production was 9,365 BOE per day, representing an 18% increase over the same quarter last year, and I remain confident that we will meet our year-over-year production growth guidance of 15% for the full year.

Our increased production came from all areas except for Hilight Fields, as Aneth Field contributed to approximately 44,000 equivalent barrels of additional production. Our Bakken activities contributed an additional 66,000 BOE, and the Permian contributed an additional 29,000 BOE.

Some quick math shows that 68% of the production growth in the third quarter came from our relatively newer assets in the Permian and the Bakken, while we still see continued growth from our legacy Aneth Field.

Our focus on production was accompanied by an equally aggressive effort to drive down well cost, and to enhance operational efficiencies; the details of which I will discuss in a moment.

As one final summary point, we ended the third quarter with a strong balance sheet and ample liquidity for funding our growth plans, and that includes acquisitions.

Drilling a little deeper, let’s turn to our foundation asset, Aneth Field, which is the source of the majority of our oil production and which generates free cash flow for reinvesting in our projects in the Permian and Williston Basin.

The third quarter, our Aneth Field properties produced 6,399 BOE per day, up 8% from the same quarter last year. As compared to the second quarter of this year, Aneth Field production is down by about 250 BOE per day, but keep in mind that we sold production and reserves to Navajo Nation Oil and Gas during the third quarter.

Our year-over-year production increased in Aneth had many contributing factors, including on-going responds from Phases 1, 2, and 3 of our CO2 expansion project. Initial response from Phase 4, contribution from our DC IIC program, drilling new wells and sidetracking existing wells, and increasing run times and efficiencies from our Aneth central compression facility, and other field equipment upgrades.

Production from Phases 1, 2 and 3 of our CO2 expansion in the Aneth unit, continues to improve with a 15% increase over the third quarter of 2011 and an uptick of 5.5% over the second quarter of this year.

Phase 4 surface upgrades consisting mainly of upgrades to pipelines, the main battery and production headers are virtually complete. Phase 4 has CO2 related production and two wells close to Phase 3 injection. The one [inaudible] producing well in Phase 4 has seen CO2 breakthrough. This bodes well for further increases in production at Phase 4.

In our DC IIC project, we completed two additional producing wells that have each averaged 100 gross barrels a day of incremental production. We are on track to having 21 producers and 26 injectors online by year end.

Recall that our recompletion efforts in the DC IIC formation began two years ago. There are 18 wells that have been producing for one to two years, and these wells are still averaging 43 barrels per day of incremental production.

The Geo team is working us pretty hard, and right now there are 44 additional DC IIC recompletions in our inventory. These projects can provide low-risk immediate-production growth over the next couple of years. I say immediate because the initial production is from a restartable – of a water play. In due course, we will start to flood the DC IIC with CO2.

In the Aneth unit, five more wells were sidetracked and completed during the third quarter, contributing to initial production rate of approximately 130 gross BOE per day. We plan to sidetrack three more wells in the fourth quarter with gross cost of approximately $650,000 for sidetrack.

Also helping to drive production higher was improved run time at the Aneth Central Compression facility with third quarter runtime at 95% up, up from 90% in the second quarter. Improvements from this facility increased CO2 reinjection capacity and condensate production. And they reduce flaring and backpressures across the field.

Facilities current reinjection capacity is 45 million cubic feet of gas per day, and we’re on track to increase that 33% to 60 million cubic feet per day by year-end. This expansion should facilitate additional increases to field wide production.

As a result of our activities across the Aneth unit, daily production there has increased by an impressive 22% over the first nine months of the year. That was a good lead in to where we are redeploying cash generated from our Aneth Field.

During the third quarter we operated continuous drilling programs in our other two primary growth areas, in the Bakken, Oil Shale play in North Dakota, and then the Permian Basin of Texas.

In North Dakota we produced an average of 919 BOE per day, net to resolute during the third quarter of 2012. That’s up 362% from the 199 BOE per day produced in the same quarter of last year, and up 20% from the 765 BOE per day produced in the second quarter of 2012.

This increase was driven by placing 10 gross, or 2.2 net wells on production, bringing our total producing well count to 49 gross, or 11.9 net wells, while 5 gross .8 net wells are waiting on completion.

We own leasehold interest in 23,500 net acres in our New Home project, where the operator replaced one of the conventional rigs with a newly built walking rig. We’ve already begun to capture benefits from the new rig as the AFE cost decreased to 7.7 million in the third quarter, down from about $8 million earlier in the year.

We are looking for additional cost reduction as the crew gains more experience. We are well ahead of the pace we estimated at the beginning of the year, and at our current drilling pace, we are on track to have the core of this acreage held by production, by year-end 2013.

In our Paris project area, we hold 19,000 or 8,500 net acres. There we finally overcame the mechanical issues and completed the fraced stimulation of the Forest well, and it came on line with a 30-day IP rate of 562 BOE per day. We expect further activity in the Paris project during 2013.

Switching over to our assets in the Permian Basin, we produced 600 BOE per day, net to resolute during the quarter. Up 111% from the 284 BOE per day produced in the prior year quarter, and up 41% from the 427 BOE per day produced in the second quarter of 2012.

During the quarter we brought six roles, or four net wells on to production, bringing our total well count to 25 gross, or 18.1 net wells. We currently are drilling 3 gross or 2 net wells.

In Reeves County in the Delaware Basin, we control approximately 22,500 gross or 8,100 net acres, respective for Wolfbone production. There we have 14 gross or 7.1 net wells on production as of the end of the quarter.

A major effort in this area has been placed on cost reduction, both from a drill and complete standpoint and from a lease operating standpoint. On the [inaudible] side, we have constantly revolve our completion methodology as we acquired new data with each new well.

This has let us to reduce the number of frac stages, which in turn has reduced completion cost and water disposal volumes without any apparent impacts to initial production rates or forecast of ultimate recoveries.

Also, our drilling crews are getting better, reducing drilling days to 25 days down from 30 to 35 days in the second quarter. These improvements have contributed to a reduction in drilling and completion cost, from approximately $4.1 million to approximately $3.5 million per well.

On the lease operating side, two major initiatives should lead to reduce cost in a going forward basis. First, we have replaced well site leased generators with what, for a lack of a better term I’ll call City Power. Second, we brought on line a water disposal well, and we’re in the process of laying water flow lines to that disposal well. Together we expect these initiatives to reduce [inaudible] substantially.

For example, rental generators at each location cost about $25,000 per location, per month, including fuel. Whereas, we estimate that the new electrical system will cost about $5,000 per location, per month. So that’s going from 25,000 per location per month to 5,000 per location, per month.

In addition, water disposal cost are about $4.50 per barrel, before we installed the disposal well and water lines. We expect that cost to be about $0.50 per barrel, in other words, from 4.50 to $0.50 when the disposal well, or the disposal system is fully operational.

I would note that EOG is acting immediately south of our leases, and we have had some informal conversations about their use of our power and disposal facilities.

In the Midland Basin we reduced total drilling days by approximately 5 days, decreasing drilling and completion cost to $2.8 billion in the third quarter, as compared to $3.1 million in the second quarter. During the quarter, we brought on production 2 gross and net wells. We have 1 gross and 1 net well IIC devoiding a frac, and 1 gross and 1 net well of drilling.

I’d like to touch on our Hilight Field and the Powder River Basin. I mentioned previously the production there declined. That decline was approximately 4.5% from the third quarter of 2011. Decline in this field is to be expected as it is a mature field. However, year-over-year production was significantly impacted by our shut-in of an economic coalbed methane well, and more recently by the outage of the Anadarko Hilight processing plant for scheduled maintenance during August.

Considering these factors, I’m quite pleased with the overall performance of Hilight Field.

Also, our technical team has developed an improved screening program to identify the most promising refract candidates in Hilight, based on their analysis of our multi-year program. As a result, in the third quarter we resumed our refract program targeting in the Muddy formation. We’ll continue that project as long as it meets our economic targets.

In sum, we will continue to reinvest cash flow in to our growth projects in Utah, Texas, and North Dakota, as we build a conveyer of new wells to drive growth. And it is important to mention again that our team is focused on improving cost efficiencies and implementing new technologies and techniques to enhance production and cost savings.

I will now turn the call over to Ted Gazulis, to discuss our financial results in more detail.

Theodore Gazulis – EVP, CFO

Thank you, Nick.

As Nick discussed, our third quarter results were in line with our growth plan. And we're continuing our development operation in the Bakken trend, the Permian Basin, and in Aneth Field. We're on track to achieve our production guidance of 15% full-year growth. And continue to improve capital cost efficiencies investing in additional infrastructure and improving drilling in completion techniques.

In the third quarter of 2012, total company production was 862,000 equivalent barrels compared to 729 MBOE for the third quarter of 2011 achieving an 18% increase over the same quarter as last year.

Production for the nine months ended September 30th was 2,482 MBOE, a 15% increase compared to the 2,165 MBOE for the nine months ended September of 2011.

Revenue, excluding realized derivative settlements in the third quarter of 2012, rose to $63.4 million. 17% higher than the year ago period driven primarily by the production increases that I just mentioned.

During the period, the average realized revenue per Boe excluding realized derivative settlements was $73.58 of Boe, less than 1% lower than the $74.15 of Boe in the same quarter last year. For the first nine months in 2012, revenue per Boe excluding realized derivative settlements decreased about a half of percent comparatively to $77.12 of Boe as compared to $77.59 of Boe.

Not entirely surprisingly, with rising production came increases in operating expenses. Our aggregate lease operating expense in the third quarter of 2012 rose to $21.3 million from $14 million in the same quarter in the same quarter last year, an increase of about 9% sequentially from the second quarter as we ramp activities in both the Bakken trend and Permian Basin and continued our work in Aneth Field.

I would point out that our increased work over in activity in Aneth Field flows through our income statement in the period incurred while the benefits of added production are seen over time. We're comfortable that the longer-term production benefit well outweighs the short-term increase in LOE. For the nine month period, aggregate LOE rose to $58 million from $42.7 million.

Aggregate production taxes in the third quarter of 2012 increased to $8.4 million or 13.3% of revenue from $7.6 million or 14.1% of revenue in the third quarter of 2011. This decrease in production tax rate was attributable to receipt of enhanced oil recovery credits in Aneth Field during the third quarter of 2012. For the nine month period, production taxes rose to $28.3 million from $23.6 million, a 4% increase over the prior year period representing about 15% of revenue.

Turning next to general and administrative expense, we incurred $6.7 million or $7.74 of Boe of G&A for the third quarter of 2012 as compared to G&A expense of $5.5 million or $7.50 of Boe during the same quarter last year. For the first nine months of 2012, G&A expense was $17.6 million or $7.08 of Boe compared to $14.6 million of $6.73 of Boe during the first nine months of 2011.

As our company has grown, we've added significantly to our technical staff and our operational team. And that's clearly in [inaudible] of shareholders. But of course, we incur additional G&A. This leads us to adjusted EBITDA, a non-GAAP measure. In the third quarter of 2012, we generated adjusted EBITDA of $26.4 million or $30.66 of Boe. That was a 1% increase in aggregate adjusted EBITDA from the prior year period.

During the nine month period ended September 30th, 2012, resolute generated $76.8 million of adjusted EBITDA or $30.93, a 4% decrease in the aggregate adjusted EBITDA amount from the prior year period.

In both the three and nine month period, increased production and flat pricing were offset by increased operating costs, production taxes, and administrative expenses resulting in a somewhat larger percentage decrease as in EBITDA for Boe.

Next, let me talk about our capital program. We invested $59.3 million during the third quarter of 2012 bringing our total for the nine months to $162.2 million, which includes $37.7 million used to acquire Danbury's interest in Aneth Field. Absent the Danbury acquisition, capital expenditures through the nine months were $162.2 million as compared to the $190 million amount for the full year. We invested $37 million in the first nine months of 2012 on work-over rigs and ongoing tertiary projects in Aneth. We invested $49.8 million to drill 15 wells and complete 24 wells in North Dakota. And invested $53.7 million to drill five wells and complete 13 wells in Texas. We expect to continue to invest in our Bakken, Permian, and Aneth areas through the fourth quarter of 2012.

Finally, I'd like to talk about liquidity. At September 30th, 2012, we had outstanding borrowings under our revolving credit facility of $18 million. The credit line has a borrowing base of $330 million and does not mature until 2017. Between cash flow from operations and borrowing capacity under our revolving credit facility, we expect to fully fund the balance of our 2012 capital program and to have the financial resources needed to take advantage of opportunities to strengthen our strategic position.

Also as you may recall, further enhancing our cash position, we expect to receive approximately $45 million as adjusted for production and other costs from the Navajo Nation of the oil and gas company during the first week of January in 2013 as we complete the previously announced sale of properties to them.

With that, I thank you all for listening and I'll turn the call back to the operator for Q&A. Rachel.

Question-and-Answer Session

Operator

(Operator instructions). Your first question comes from the line of John Freeman from Raymond James. You line is now open.

John Freeman – Raymond James

Good afternoon, guys.

Nicholas J. Sutton – Chairman, CEO

Hey, John.

John Freeman – Raymond James

I just – looking at the production, you know, congratulations on, you know, being what looks like you’re going to be easily on track to hit the full-year production guidance. I’m just sort of looking at, you know, if your production was basically flat in fourth quarter, you basically would be at the midpoint of your guidance – I’m just looking at, you know, as you all have mentioned, North Dakota and Texas, you know, driving 68% of the growth, and it looks like it’s kicking into growth again after that Navajo Nation sale. I’m just trying to see if the guidance – do you all kind of think of it just kind of being kind of conservative? I don’t see why production probably wouldn’t still grow in the fourth quarter versus third quarter.

Nicholas J. Sutton – Chairman, CEO

I think the underlying question is, are we going to change our guidance, and the answer is no, we are going to stay right where we are, John. I think we’re being appropriately conservative on our guidance. I agree with you, that the 18% is a good number, I would also say that we are now in the at that stage of the year were we are getting into winter, and I always hate to be overly optimistic about product as we hit the winter months as we have weather issues, freeze up issues, and things of that nature that could come into play.

John Freeman – Raymond James

Okay, and then next question shifts into the Permian – I apologize if I missed this, but the salt water disposal well that’s going to have a good bit to drive down the disposal cost there, when is that expected to be fully operational?

Nicholas J. Sutton – Chairman, CEO

The well itself is operational right now, and we are in the process of laying water flow lines. We have some water flow lines in place, and those are operational in the areas we have yet to put the water flow lines in, we are trucking, but of course we are trucking right there in our neighborhood, so those costs are reduced right now. Fully operational, I would say by the end of the year would be my current estimate, but you’re right, it should bring down both LOE, and frankly, it will bring down a component of our drawing completion costs, because as you know, early stage of flowing back a well as part of the well cleanup after that there is a lot of fluid produced, and that has been disposed of at the higher cost in past wells, and going forward we expect it will be disposed of at the lower cost. So, we will get some impact, both on our LOEN, and on our drilling completion costs.

John Freeman – Raymond James

Okay, and just last question from me, you’re dropping the one rig in the Wolfbone, maybe if you could just sort of elaborate on the decision process there?

Nicholas J. Sutton – Chairman, CEO

Sure, the decision process is simply that we’re well ahead of our project to stay ahead of our leases, and we are building, and have spent money on infrastructure, and we think it’s appropriate just to pull back a little bit over the [inaudible], as we fully absorb those infrastructure costs into our system.

John Freeman – Raymond James

Thanks a lot guys, I appreciate it.

Nicholas J. Sutton – Chairman, CEO

Thank you, John.

Operator

Your next question comes from the line of Noel Parks from Ladenburg Thalmann. Your line is open.

Noel Parks – Ladenburg Thalmann & Co.

Good afternoon.

Nicholas J. Sutton – Chairman, CEO

Hey, Noel.

Noel Parks – Ladenburg Thalmann & Co.

Just a couple of things – as you take a look more into 2013, and your budget process, [inaudible] in front of you, is it pretty much a set and determined list of where you’re going to spend it at this point, or is there still a lot of sort of variability, or questions, or tradeoffs to evaluate as you look to throw off those numbers?

Nicholas J. Sutton – Chairman, CEO

Though we’re still on our process as we go through our 2013 planning process, and all the teams are working hard, and we have a couple of iterations to go certainly before we settle on numbers and outline our overall, sort of, scope of tasks for 2013, so we’re really not in a position to pre-announce anything with respect to 2013. You are absolutely right, we’ve got a lot of things on our agenda, a lot of, sort of, goodies on the shelf, and we’re going to go through a rational process of allocating capital consistent with the overall objectives of our company.

Noel Parks – Ladenburg Thalmann & Co.

Okay, great, and just a housekeeping item – do you have any, sort of, ball park thoughts that you can give on what stock compensation is going to look like maybe for fourth quarter, and first quarter next year?

Nicholas J. Sutton – Chairman, CEO

I don’t know that I could get any more granular than looking at what it’s been over the last couple of months. I would not expect that it’s going to materially change as we go forward from recent quarters into the next quarter or two. So, I think that’s a pretty good look, and I don’t think I could refine that number any better than that right now, Noel.

Noel Parks – Ladenburg Thalmann & Co.

Okay, good enough. Just a last thing – you know, I was reading – finally heading into winter, and you know, everyone is wondering about what gas prices are going to do. In sort of a bullish scenario, if we saw, you know, weather cooperating, prices strengthen – where would you guys stand in terms of your ability to, you know, increase gas production – I don’t know where would be, maybe in Highlight, have – are there rigs locally still that all the equipment, you know, moved out of the basin, so forth?

Nicholas J. Sutton – Chairman, CEO

I don’t see rigs as being a real consideration, certainly Highlight is the gassiest of our project areas right now, although we, as you know, in Reeves County, we produce some gas, our [inaudible] carbon stream is roughly a third oil, a third NGL, and third gas. So, we would reap some benefits there as well, but we are, you know, basically a 90% oil company, and its – without going out and making a conscience effort to insert ourselves into more gas prone areas, I just don’t see gas as being a big factor in our

Operator

Your next question comes from the line of Richard Tullis – Capital One Southcoast, Inc. Your line is now open.

Richard Tullis – Capital One Southcoast, Inc.

Thank you. Good afternoon everyone.

Nicholas J. Sutton – Chairman, CEO

Hello Richard.

Richard Tullis – Capital One Southcoast, Inc.

Just a couple of quick questions, Nick. Looking at the drilling program for 4Q, how many net wells do you expect will be drilled between Delaware Basin, and Midland Basin specifically?

Nicholas J. Sutton – Chairman, CEO

I’m sorry, but I don’t have at the tip of my finger. I mean we have one rig working in Reeves County. I’m looking at our team in Denver, and Sean, do you have any better idea, you know on actually well count for Williston.

(Unidentified Company Representative)

I believe – This is Sean speaking. I believe the count in Texas will be three gross in Delaware, two net for the rest of the year. And in Midland, I believe it’s just one more for the rest of the year, one gross and one net.

Richard Tullis – Capital One Southcoast, Inc.

Okay, good. Thank you.

Nicholas J. Sutton – Chairman, CEO

Preston, do you have anything you want to add with respect to Williston?

(Unidentified Company Representative)

Approximately two net in North Dakota, that’s with the two rig program, and taking the gross wells on our current sort of drilling schedule, and then it gets down to about two net.

Richard Tullis – Capital One Southcoast, Inc.

Okay. And looking a little bit out to next year given that I guess some of your acreage in Midland Basin is held, at this point do you look at similar type ratio next year in Texas?

Nicholas J. Sutton – Chairman, CEO

As I mentioned before, we are in the middle of our planning process and I just am not comfortable prejudging where that is going to turnout. As I mentioned before, we’ve got a lot of people who are working the various assets in the various areas. And it’s got a couple of iterations left to go. I understand that you’re trying to build your best models up to 2013, and believe me Richard we will provide you with the appropriate information when it’s a little bit more, I would say solid then just at this stage of our planning process.

Richard Tullis – Capital One Southcoast, Inc.

That’s fine. At the opening you touched a little bit on M&A Nick, I know you have lots of liquidity. Where are you guys right now with your outlook on M&A, or potential M&A?

Nicholas J. Sutton – Chairman, CEO

Well, as you know, we worked that pretty hard. We’ve got a business development group that goes through a lot of projects, and certainly there’s a lot of activity out there right now. I think some of the private equity type companies are looking to try to do transactions before the end of the year, and arguably increasing tax rates in 2013. So it’s a very active market, we are out there evaluating everything, well not everything obviously, but everything that we think is appropriate for us to evaluate. And you know the deal with M&A you have kiss a lot of frogs to find something that really works. [Inaudible] and we’ll see. Certainly a key thing is, we do have good liquidity, and a good balance sheet, and we’ll see what develops.

Richard Tullis – Capital One Southcoast, Inc.

Thanks very much, I appreciate it.

Nicholas J. Sutton – Chairman, CEO

Thank you Richard.

Operator

Your next question comes from the line of Ron Mills – Johnson Rice. Your line is now open.

Ronald Mills, Johnson Rice & Co.

Good afternoon. I want to ask about the 2013 budget, I’m just kidding. For LOE, you talked about not just work overs in Aneth moving over to, you know, extending more into the third quarter than I think I thought, but also the spending on electrical infrastructure of the salt water disposal at all in the Permian. You know, if you look at the fourth quarter and even somewhat into next year, have you guys thought of the order of magnitude that that can have on LOE improvements? You know you’ve pushed into the low 20’s per boe, up from the 17 to 19 dollar range that you’ve been at in the past. Is that past number a goal that you have going forward, or I’m just trying to get a sense of the magnitude of the corporate unit cost on the LOE side, when we have it more normalized?

Nicholas J. Sutton – Chairman, CEO

Our goal is certainly to drive them down. One of the things that – I think that right now we believe that Aneth us going to move down more into its traditional range. We think that the activities in the Permian should help a great deal. The Bakken is, it just depends, much of our activity there is third party operated. One of the other things that we didn’t really talk about much is just the production tax component of the expense equation. And, you know, with more production and more robust product prices, particularly in Aneth, the taxing authorities have taken the view that the property is worth more, so that the asset value based tax component has gone up. That’s not likely to come down as long as we continue to increase production. So, as you look at the production tax line, don’t expect much change there. But on the pure LOE line, our goal is to drive them down to more or less where they were before. Whether that all will come in Q4 remains to be seen, but I would in your model building – if I were building a model, I would reduce it somewhat between where it’s been and the more recent history.

Ronald Mills, Johnson Rice & Co.

And do you guys have – is there an appreciable difference in LOE per area from the Aneth to the Permian to the Bakken, just as that production mix changes, you know, how can that impact the overall rate. Because historically you were really, you know, your cost per based on Aneth. So are the Permian and Bakken similar type targets of LOE per unit, or do they differ for whatever reason?

Theodore Gazulis – EVP, CFO

You know – this is Ted. You know Aneth has historically had a higher lease operating expense than either of the other areas. When you look at Wyoming, when you look at the Bakken, when you look at Permian, I can’t say that the lease operating expenses there are half of what they are in Aneth, but they are[inaudible] of what they are in Aneth. So, as we continue to increase production in those other areas, we absolutely expect to see a dampening if you will of the affect that Aneth on aggregate company LOE. Now having said that, we continue to have most of our production from Aneth, so it’s not as though you’re going to see an enormous change instantly, but that change will occur as we move forward through time, and we end up with more production from the other areas relative to the amount of production that we see in Aneth.

Ronald Mills, Johnson Rice & Co.

And that was what I was trying to get at, it would just seem that your historical unit cost or, even once you get past these non-recurring if you will expenses is bias even lower than you were historically just because of the Permian and Bakken on a unit base.

Theodore Gazulis – EVP, CFO

That’s absolutely a fair statement.

Ronald Mills, Johnson Rice & Co.

Okay, good. To follow up on Richard’s question on the M&A, you know obviously with the liquidity and everything he reference, but it sounds like the M&A market is pretty active across all of the basins. I’m assuming is your focus still really on building mass in the Permian and Bakken first, or is the whole world your oyster and you’re looking at other potential growth areas as well?

Nicholas J. Sutton – Chairman, CEO

Our focus right now, Ron, is really on adding to the core areas that we have. Certainly there are other parts of the country that have attractive attributes, but I think given where we are right now as a company, we can better serve our shareholders by getting more horsepower, more mass in some of our core areas. We’re already operating – you know, we’ve got a good office in Midland, we’ve got good people working out of that Midland office. I think that’s a good indication of where we’re providing our focus right now. So, don’t look to us – never say never, and we’re here to make money for our shareholders. So I say “If I can buy $5 worth of product for $2, I’m going to go ahead and do it”. But we’re really right now focused on building where we’re already on the ground…

Operator

Your next question comes from the line of Brian Ottman from Suntrust. Your line is now open.

Brian Ottman – Suntrust

Good afternoon, guys.

Nicholas J. Sutton – Chairman, CEO

Hi, Brian.

Brian Ottman – Suntrust

Congratulations on the Bakken completion in the Paris area, you know, you guys reported a first 30-day rate well over 500 barrels of oil quote per day. Is that fair to say that that, you know, is tracking above that typical – that curve guidance of 300 to 400,000 barrels?

Nicholas J. Sutton – Chairman, CEO

Good question. I’ll just remind folks that we are really in two areas in the Bakken. We have our next home area, which is operated by no Halcon after the acquisition of GeoResources and that’s a little bit to the northwest as you look at the overall basin of the Wilson basin. Our Paris acreage is to the southeast of Newhome and so it’s in a slightly different geologic setting, it’s a little bit deeper and we would expect to have different results there. The wells are going to be slightly more expensive but the production in that area is certainly higher than the 350, let’s say, type curve. And our belief is that we’re talking more like a 500-type curve. It could be in excess of that up on the eastern and northeastern part based on some offsetting production, but we think that’s a good conservative number.

Brian Ottman – Suntrust

Okay. And I know it’s tough to kind of get at a well cost given the mechanical issues in this first well, but what do you guys expect there on a run rate basis in Paris?

Nicholas J Sutton – Chairman, CEO

I’m thinking 9, 9.5 million per well.

Brian Ottman – Suntrust

Okay. Okay, and then shifting on you, you know, to NGL prices, you know, it looks like those were down about 30% quarter-to-quarter, about half where they were in 4Q. Can you offer any color on the most recent decline and kind of what you guys expect for prices there moving forward? Is there any issue that you can point to, you know, directly or is kind of the steady state a fair assumption moving forward?

Nicholas J. Sutton – Chairman, CEO

My way of looking at it is it’s kind of steady state in that if we look at it from a national standpoint, the NGL markets have been under pressure simply because of the focus on liquids-rich gas by a lot of the former, I kind of use former in quotes, natural gas oriented companies. As they look at their inventory, they’re drilling hard on the liquids-rich component and of course, what that means is we’ve got a lot of NGLs that are coming on the market and it will take a little while for I think the national markets to sort out where NGLs can be used and beyond where they’re already in use. So certainly the drop in price will encourage more consumption and more infrastructure build out for those plans in various other uses for NGLs. So I think right now we’re just at that low point, but I would not project a timing for an increase in NGL prices. I think we’re going to continue to be under pressure as long as the natural gas guys are drilling as hard as they are in places like the [inaudible], the Eagle Ford or the Granite Wash, places like that.

Brian Ottman – Suntrust

Okay, that’s helpful. Thank you, guys.

Nicholas J. Sutton – Chairman, CEO

Okay, thanks, Brian.

Operator

(Operator instructions). Your next question comes from the line of Jason Wangler from Wunderlich Securities. Your line is open.

Jason Wangler – Wunderlich Securities, Inc.

Good afternoon, guys.

Nicholas J. Sutton – Chairman, CEO

Hi, Jason.

Ted Gazulis – EVP, CFO

Hi, Jason.

Jason Wangler – Wunderlich Securities, Inc.

Hey, sticking with the Paris area and obviously the nice results there, could you just maybe talk about as you get into ’13, I know you’re still working on the budget and things, but when abouts you’d be looking to get out there? Do you have permits already in hand or anything from the previous operators? Just kind of what you’re looking at as far as timing going forward?

Nicholas J. Sutton – Chairman, CEO

Sure. We are looking at picking up activity there. Just to refresh your recollection, Marathon was the prior operator and Marathon with its massive acreage position the Bakken play, not focused on Paris simply because it had too much other [inaudible] with the separations in front of it. So they had pushed Paris off to 2014, 2015-ish on their schedules and by taking over operations, we have the ability to accelerate and we expect that Marathon will participate to the extent of its acreage that’s in there because cash wasn’t their issue, it was really a people issue.

So we have moved forward with permitting. We are at just about – well, to put it this way, close to having permits on approximately three locations and we’re working on another three locations and that – the first three, I think, will be ready to go somewhere Q1, into end of maybe early-Q2 and the second group of three, we’re working through all the environmental [inaudible] issues, the archeological issues and all the things that go along with drilling these days and so it might be a little bit longer before that’s all in hand, but you know, the teams are working it hard, they’re on the ground, they’re meeting with the BLM, they’re meeting with all the appropriate officials and we’re trying to get ahead of leases. But I think we’re in pretty good shape for 2013.

Jason Wangler – Wunderlich Securities, Inc.

Great. And the maybe one real quick for Ted, just on the credit facility. Obviously the transaction with Danbury and then with NNOGC and the other one upcoming here in a bit, do you expect anything to change as far as the availability on the lines on the 330 or do you think that’s pretty much a good steady state and when you go into termination time?

Ted Gazulis – EVP, CFO

I don’t think there’s any reason for us to – let me start this a different way. At the end of the day, I think it will stay where it is. I think that if we wanted to push it, we could, but from my perspective, I know that the assets are solid, I know that we’ve got a terrific bank group, I know they’ve always been supported and if we’re ever to need to push the envelope, we could certainly do so. But at this point, I’m not sure that I see any need to do that, nor do I see any real likelihood that the bank group’s going to come down and – come back and say, gee, let’s ratchet this down.

Jason Wangler – Wunderlich Securities, Inc.

That’s helpful. Thank you, guys.

Nicholas J. Sutton – Chairman, CEO

Thank you, Jason.

Operator

There are no further questions at this time, I’ll turn the call back over to our presenters.

Nicholas J. Sutton – Chairman, CEO

Well, thank you, everyone. We appreciate your listening in on the call. We think that we had a very good quarter. I think the year is stacking up to be a very good year. We’ve been heavily focused on production ads and I would point out, reiterate what Ted said, is a good bit of the LOE was dedicated to workovers and re – just brining wells onto production so that all hits the P&L at one time but the production impact is going to be felt in upcoming months and quarters.

So again, we think it’s a – been a good quarter. It’s stacking up to be a good year and as we go onto our 2013 planning process, we have a lot of projects that are fighting for capital and we look forward to being able to share that information with you as soon as reasonably possible.

Again, thank you very much.

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