Northern Oil and Gas Inc (NOG) 2011 Q2 法說會逐字稿

Good day ladies and gentlemen, and welcome to the Northern Oil and Gas second quarter earnings release conference call. Please note that today's call is being recorded. At this time all participants are in a listen-only mode, later in the call there be a question-and-answer session with Northern covering analysts. (Operator Instructions).

I would now like to turn the call over to our host, CEO, Michael Reger. Sir, you may begin.

Thank you. Good morning, ladies and gentlemen. My name is Michael Reger, I am the Chairman and Chief Executive Officer of Northern Oil. Ryan Gilbertson, our President, is also here on the call with me today, we are excited to welcome you to our 2011 second quarter earnings call for Northern Oil.

Before we begin this morning's call, you should be aware that certain statements made during this call may contain forward-looking statements that are based upon management's expectations, projections and assumptions that involve certain risks and uncertainties. We encourage you to review the various Risk Factors relating to our business, which are available on our Annual Report on Form 10-K for the fiscal year ended December 31st 2010, and other reports we have filed with the SEC. These forward-looking statements relate to our future plans, objectives, expectations, and intentions. Our actual results could differ materially from those contemplated by these statements, partially as a result of the various assumptions relied upon in making such statements.

For those of who are joining to learn more about Northern Oil and Gas for the first time, I would like to take a moment to explain our operational strategy in the Bakken and Three Forks play in Montana and North Dakota. As a non-operator we participate in wells on a heads-up basis in proportion to our leasehold interest in drilling units. Any time a well is permitted all parties controlling leasehold interests within the drilling unit are automatically included in the well. As such Northern Oil's leasehold interests are included in any wells drilled within drilling units containing our interests. As an example, we control 16 acres in the 640-acre drilling unit, we would own 25% of any well drilled in that unit, and participate heads-up with a 25% working interest.

When a well is drilled in the units, we then pay our 25% share of all expenses, and receive 25% of all crude oil and natural gas sold from that well less our royalty burden. We do not farm out our interests or dilute our working interest in any way. We just participate heads up for our proportionate working interest without the infrastructure and overhead costs of our operating partners. We believe capital is most efficiently deployed through this strategy, due to the substantial discount for which non-operated leasehold interests can be obtained.

With that background in mind, I would like to now turn the call over to Northern Oil's President, Ryan Gilbertson, to review our financial and operating results for the quarter.

Thanks, Mike. Oil and gas sales for the second quarter of 2011 were $35.5 million. This represents a 204% increase, compared to oil and gas sales of $11.7 million for the second quarter of 2010. These results also represent a 31% increase in oil and gas sales during the second quarter of 2011, as compared to the first quarter of 2011.

Production volumes for the second quarter of 2011 were a quarterly record 400,928 barrels of oil equivalent, which represent a 132% increase compared to the second quarter of 2010 and a 12.5% increase compared to the first quarter of 2011. The second quarter production volumes represent Northern Oil's 14th consecutive quarterly increase in production.

Average daily production in the second quarter of 2011 was approximately 4,400 BOE per day. June 2011 daily production averaged approximately 5,200 BOEPD an improvement from April 2011 and May 2011 average daily production which was affected by heavy rain, flooding and road restrictions in North Dakota and Montana. Second quarter 2011 production consisted of approximately 94% crude oil, and 6% associated natural gas and other liquids. Northern Oil does not include flared and unsold gas volumes in its production figures.

During the second quarter of 2011 Northern Oil spud approximately 7.2 net wells,and added production from 73 gross, or 6.7 net wells. During the first half of 2011 Northern Oil spud approximately 17 net wells, and added 128 gross, or 11.71 net wells to production. Northern Oil reaffirms that it expects to spud at least 40 net wells throughout 2011.

Northern Oil continues to develop its core Bakken and Three Forks acreage position at an accelerating pace. According to the North Dakota Industrial Commission, 187 rigs are drilling in North Dakota as of August 8, 2011. Approximately ten rigs are currently drilling in Montana as of August 8, 2011. The significant rig increase in the play continues to accelerate the development of Northern Oil's core acreage block. Northern Oil has maintained a 100% drilling success rate in the Williston Basin Bakken and Three Forks trends since the Company's inception.

Northern Oil's average realized crude oil sales price for the second quarter of 2011 was $80.78 per barrel, after taking into account a $14.91 per barrel loss due to the settlement of crude oil derivative contracts. This compares to an average of $74.10 realized price in the first quarter of 2010, which took into a $9.73 per barrel loss due to the settlement of crude oil derivative contracts. Northern Oil's average realized crude oil sale price for the six months ended June 30 2011 was $77.63, after taking into account a $12.47 per barrel loss due to the settlement of crude oil derivative contracts. This compares to an average of $70.02 per barrel of realized price for the first six months ended June 30 2010, which took into account a $0.44 gain due to the settlement of crude oil derivative contracts.

Production expenses for the second quarter 2011 were $5.94 per barrel on an accrued basis, compared to $3.30 per BOE on an accrued basis for the second quarter of 2010, and $5.24 per BOE on an accrued basis for the first quarter of 2011. The increase in production expense is primarily due to lower production volumes, due to heavy rain, flooding and road restrictions that continue to date in the producing oil and gas properties, exposure to new operators in new development areas, an increase in working interests, mature wells utilizing artificial lift, and the general maturation of the production.

Depletion expense for the second quarter 2011 was $8.3 million, or $20.83 per BOE. As such Northern Oil's second quarter 2011 depletion expense is consistent with its peer group in the Bakken and Three Forks play. G&A expense net of share-based compensation for the second quarter of 2011 was $1.2 million, compared to $1.4 million for the first quarter of 2011. Share-based compensation for the second quarter 2011 was $1.5 million compared to $1.9 million for the first quarter in 2011. The decrease in G&A expense is primarily due to the reduction in share-based compensation, a reduction in professional and additional consulting services.

Adjusted EBITDA for the second quarter 2011 was $22.7 million, or $0.37 per fully diluted share, which represents a 135% increase over adjusted EBITDA of $9.7 million, or $0.19 per fully diluted share for the second quarter 2010, and a 22% increase compared to the first quarter of 2011.

Northern Oil defines adjusted EBITDA as net income before interest expense, income taxes, depreciation, depletion and amortization, accretion of abandonment liability, pre-tax unrealized gain and losses on commodity risk instruments, and noncash expenses relating to share-based payments recognized under Accounting Standards Qualification Topic 718.

Net income excluding unrealized mark to market hedging gains or losses and adjusted EBITDA are non-GAAP measures. A reconciliation of this measure to GAAP and net income excluding the effect of unrealized mark-to-market gains from oil hedge is included in our Company financial tables found later in this release. Northern Oil's management believes the use of nonGAAP financial measures provides useful information to investors, to gain an overall understanding of current financial performance.

Specifically, management believes the non-GAAP results included herein, provides useful information to both management and investors by excluding certain expenses, unrealized commodity hedging gains and losses, that management believes are not indicative of Northern Oil's core operating results. In addition these non-GAAP financial measures are used by Northern Oil's management for budgeting and forecasting, as well as subsequently measuring Northern Oil's performance. Management believes that Northern Oil is providing investors with financial measures that most closely align to its internal measurement processes.

On August 8th, 2011 Northern Oil amended its senior secured revolving credit facility with Macquarie Bank Limited, to provide that the aggregate maximum credit amount may be increased up to $500 million. The amended facility also provides for an initial borrowing base of $150 million subject to the aggregate maximum credit amount then in effect. Initially the amended facility provides for an aggregate maximum credit amount of $25 million, that can be increased in increments of $20 million up to $500 million, subject to applicable conditions and increases in lender commitments. Financing under the amended facility is equal to the lesser of the aggregate maximum credit amount and the borrowing base. Northern Oil currently has no outstanding borrowings under this facility.

As of June 30th, 2011 Northern Oil had a total volume of open commodity swaps of just under 1.5 million-barrels of oil at a weighted average price of approximately $88.13. These contracts settled between July 2011 and December 2012. In addition to the swaps in place Northern Oil has 243 barrels of crude oil collared between $85.00 and $101.75, that settle between July 2011 and December 2011. Northern Oil reaffirms that it expects to spud at least 40 net wells in 2011, with drilling CapEx approximating $260 million,up from $252 million.

Average well costs are expected to now approximate just under $6.5 million per well, up from $6.3 million per well. The increase in drilling and completion costs is due to a higher percentage of our wells in the second half of 2011 that will be drilled on 1,280-acre spacing units, utilizing longer laterals and an increased number of fracture stages. Based on current yet evolving conditions in the field, Northern Oil expects to continue to deploy additional funds towards future strategic acreage acquisitions during 2011. Northern Oil currently expects to spend approximately $20 million per quarter on acreage acquisitions through the remainder of the year, consistent with our previous guidance.

Northern Oil currently expects to fund all 2011 drilling commitments and acreage acquisitions using cash on hand, cash flow, and its currently undrawn credit facility. Northern Oil currently has no debt. During the second quarter of 2011, Northern Oil acquired leasehold interests covering an aggregate of 12,767 net mineral acres, for an average of just under $2,000 per acre, and an aggregate capital expenditure of $25.5 million. Of the acquired 12,767 net acres, approximately 7,150 net acres, or 56% were permitted or in an approved drilling spacing unit, under the bit, or began producing as of June 30th, 2011. Northern Oil currently controls just over 155,000 net acres in the Williston Basin, Bakken and Three Forks play.

As of August, 9th 2011 Northern Oil had just over 46,000 net acres, either held by production or under the bit, which represents approximately 30% of Northern Oil's total Bakken and Three Forks acreage position as of June 30th, 2011. Northern Oil currently expects that approximately 50% of its current acreage will be held by production or under the bit by the end of 2011.

Thanks, Ryan. With over 30% of our Bakken and Three Forks position developed or under the bit, we are moving ahead at an excellent pace. Importantly, we continue to acquire acreage at prices significantly below levels indicated in recent publicly announced transactions conducted by other industry participants. We believe our expertise and specialty in non-operated interest continues to yield excellent results, and will continue to add meaningful acreage, production, and cash flow. With no debt, $77 million of cash on hand, and trade receivables, we believe we are well positioned to fund the development of our core acreage position in the Bakken and Three Forks play.

Now we would like to turn it over to our covering analysts for a question-and-answer session, and we appreciate you joining the call today.

We'll take ore first question today from Peter Kissel, Howard Weil.

Hi, guys. Good morning. Couple quick questions. First of all, the well costs still remain fairly low. I know you bumped it from $6.3 million to 6.5 million, but it is still well below what some of the Street is saying, and I am just curious to see, is that a function of weighting towards Slawson, is it more short laterals being thrown into the mix, and them maybe some of your competitors, and just really any comments you have there would be helpful?

Thanks, Pete. This is Ryan. That is right. The primary driver of our average well costs being lower than the average across the play is still our heavy weighting to the east Nesson part of the play, specifically our Windsor development with Slawson, participated in these wells with Slawson, and in many cases they are 640 units, which are drilled more cheaply. The wells to the east of the Nesson anticline are typically fraced with white sand, which allows for less expense completion.

So it really just happens to be our mix of where our wells are located geographically. As we begin to participate in some other wells to the west of the Nesson, and given the drilling techniques that have been proven to be most effective out there, we will see that cost continue to ratchet up a little bit, but as long as we see that, the level of east Nesson activity, and we continue to maintain inventory there, we should be able to keep our costs generally lower than the average.

Got you. Okay. And then my second question is just this is the first quarter using Deloitte, and I was just curious to see how that transition went? I saw no restatements or anything, but just curious to hear any color you have there?

Thanks, Pete. This is Ryan again. As we disclosed I think a previous 8-K, we engaged Deloitte & Touche as our independent registered public accounting firm effective for the second quarter here of 2011. Deloitte has completed their review of our second quarter 2011, and we filed our Form 10-Q for the quarter earlier today. You will note that there are no changes or restatements to our previously reported financial statements as a result of their review. So we are very happy with the transition, we are happy to have Deloitte on board, we welcome them into the process here, and everything has gone very smoothly, as expected all along.

That is all I have got, thanks for taking my questions, guys.

Thank you.

Up next we will hear from Joel Musante, CK Cooper and Company.

Hi, guys. Most of my questions got answered, but I still have one just related to production. With the weather related curtailments in the second quarter, do you have a sense for how production might rebound for the rest of the year?

Joel, this is Ryan. We have seen a very solid rebound really that began in June. Numbers are coming in for July, and they are looking to be even more robust than they were for June, so we are expecting a pretty significant increase in July and then August as a result. It is business as usual right now in the Williston Basin right now with regard to weather, wells are getting completed at a nice pace, and we are not seeing the effect of weather affecting sort of having an effect on anything to the scope that we saw in the first two quarters. So right now, we are going to knock on wood, but it is fairly smooth sailing, and we are going to defer any guidance for the next quarter until we get a solid month or of so of non-weather affected production.

Okay.

It is tough to tell where this production comes in when so many of the wells have been shut-in or delayed in production. We have got them all ramping up now so we will be able to provide much more clear guidance once we get July and August numbers firmly under our belt.

Okay. Great. Thanks a lot.

Thank you.

We'll take the next question from Jason Wangler, SunTrust.

Good morning, guys. Just curious on the CapEx budget the $260 million, it looks like you spent about maybe $155 million for the first half of the year, and then if you want to spend $20 million each of the next two quarters on land. Am I doing the math right that it is about $30 million each quarter in terms of drilling costs?

In the first half of the year we spent about $105 million in drilling costs. Some of the wells that we drilled in the first half of the year were cheaper than the wells that we will see in the secondhalf of the year, but we believe that $260 million number looks pretty good right now. Don't see any reason to change it, and that is pretty much the right interpretation.

Okay. That is all I had. Appreciate it.

Next we will hear from Chad Mabry, Rodman & Renshaw.

Thanks. Good morning, guys. Last call you had mentioned a share buyback program. Looks like your share counts did trim down a bit in Q2. Can you give us any commentary on whether you went through with some share repurchases there, and maybe some plans going forward?

Hey Chad. Yes. We have not completed any stock repurchase under the program, because we have been in possession of material non-public information, at times when we would have desired to repurchase stock. That has prevented us from making any repurchases. We can't comment on the nature of any material non-public information that we may have, but given that fact we were unable to complete any purchases in the second quarter. We are committed to the buy back program, and as appropriate and allowable, we are comfortable making share repurchases in the market.

Okay. That is all I have got. Thanks, guys.

Phil McPherson, Global Hunter Securities has the next question.

Hi. Good morning, guys. I was just looking through the acreage reconciliation. Maybe you could help on this. As of the March 28th press release you had 151,000 acres, and then in this press release you added 12-something for a total of 155,000. So we are missing some acres there. I was wondering did things expire, was anything sold in the quarter?

Thanks for the question. This is Mike. We had approximately 6,300 net acres of expire in the second quarter primarily in [Dunn Burke], Montrail and Richland. We also sold 2,300 acres along with Slawson in our Anvil program in Roosevelt County, Montana. So that was the change.

And was that sale, I think it was a $5 million line item in the Q for asset sales? Is that the 2,300?

That is right, Phil. So we divested our Anvil project alongside of Slawson, which was about 2,400 net acres for about $5 million, and you add that to the 6,300 net acres of explorations, and that is how the adjustment gets us to just over the 155,00 we are at right now.

Yes. I think we talked about the Dunn expiring in the first quarter. So that is the same acreage, correct?

Some was in the first quarter, but the second quarter portion was about 6,300 net acres.

Okay. Great. And when you talked about spudding 17 wells in the quarter. And I know it is harder because there are so many smaller pieces, but how many do you think you have waiting on completion due to weather?

Well, the number actually was 17 so it was in the first half, so we have spud 17 wells as of June 30th. Certainly the pace of drilling in the third and fourth quarter is going to be faster than the first and second quarters. So we are very comfortable with our 40 net well guidance as a minimum, and the 17 wells that we spud in the first two quarters are right on pace for that.

I am trying to make it may be easier to get to a third quarter production number. I don't know if you guys want to give us kind of a range or not, I was trying to get to the completed well. That is the reason for the call. Maybe you can tell us what the you think the average for the year is going to be, and we can back into it. or something of that nature?

The key for us, Phil, is going to be get these July and August numbers behind us and see what the completion schedule looks like. As you know we have that data with a slight lag from the operators, so give us another three to four weeks and we will have a pretty solid idea of what the completion schedule looks like, as well as what the production profile looks like, with all of the wells turned on.

Production was so spotty throughout the second quarter, especially the first half of it, that it is hard to get a real good snapshot of all the wells producing at the level they should be, so the third quarter and the first half of the third quarter will be a good opportunity for us to get that data pulled together, and we will be able to hone in on better guidance after that.

Great. Great. And just a quick housekeeping. It looks like LOE is going up. I mean we are seeing that from everybody. Is that a better number to use going forward? It jumped up by about 10% in the quarter.

I think you will see, although we start to plateau, I know we have seen other operators pushing 8 and the high 7s, we are still a little bit under that given the nature of our production being a little bit younger, and a little bit more of it in that more highly pressured east Nesson area. You will probably see although we continue to creep up slightly as we go forward, but the second quarter I think also had the effect of numerous shut-ins in it, during which the fixed costs of the well remained the same but the production is decreased or has been eliminated. So I think you will see that number probably continue to creep up, and in our estimation plateau maybe another 10% to 15% higher from where we are.

Great. And last question and I will jump back. Given that we are seeing more rigs in Montana and more activity, what are you guys thinking? Are you getting more aggressive in that area, are you looking for more acreage as permits are filed, and what do you think the key that area is from a geological setting, is there anything in there that you can kind of give us a little look into?

Thanks. This is Mike. We will continue to acquire more acreage in Montana as the activity increase. As you know we generate a lot of our acreage acquisitions from AFEs, and certain buy areas related to areas where we have data from recent wells we have completed that are of high quality production.

We have a certain buy area that you can imagine is fairly close to the border. However, we are getting more and more comfortable moving further into Roosevelt as we continue to participate and see additional wells come in there, in that area that some other operators that are of fairly high quality. So we will generally ramp up from an acquisition standpoint as the activity increases.

Alright. Great. Thanks, guys. Appreciate it.

Thank you.

Canaccord's Marcus Talbert has the next question.

Hi, guys. Good morning.

Morning.

Just a couple of operational questions here. Looking at the completion activity in the quarter, I was a bit surprised to see the net completions up by 30% or more. Was that really a function of the improving weather that we had heard about in June, or is this more something that we should expect from the higher working interest wells that you guys are getting into more and more?

Yes. Thanks, Marcus. The increase in completions which has continued into the third quarter is driven by a lot of our focus to Slawson. Some of our biggest completion delays in the past have typically been with Slawson because they have been drilling ahead without a dedicated frac crew. Right now they are running 1.5 dedicated frac crewsto cover their six rigs. So they are being able to chew through that backlog fairly efficiently. We expect that trend to continue into the third quarter, and it is nice to see more completion assets move into the basin. We have seen a lot of operators announce commitments to dedicated frac crews, and the availability of completion assets has definitely begun to shorten the sales times and that trend will continue.

Okay. Very helpful. And that really leads into my second question here. Looking at the spud guidance it seems like it should certainly be achievable. We have been hearing more and more from your public operating partners talk about adding incremental frac crews and rigs. Outside of Slawson on the private side, are you seeing that trend from your private operators? Is there any possibilities that Slawson would add another half a crew or something going into the back half of the year here?

Thanks. This is Mike. Slawson is considering adding a seventh rig, which would potentially result in picking up another half or potentially a whole additional rig, and then giving the half a month they have for this year to the operator that they share that with. So as Slawson and everybody private and public, take it small continue to ramp up it has just going to become a factor of shortening the spud to sales time. We have already seen that across-the-board. Just given the amount of frac crews that have arrived in the basin we just particularly benefit from Slawson because we have a heavy weighting toward Slawson from a working interest standpoint, and Slawson is effectively caught up with their wells and the spud to sales time has decreased dramatically especially with Slawson.

Okay. Alright. That makes a great deal of sense. As the operators sort of try and realize efficiencies and shrink their spud to sales times, is there anything that you guys are doing from a non-operator perspective that would enable you to sort of accelerate that conversion of acreage into production and cash flow, that would sort of exceed that quarterly benchmark of 25% to 30% in the back half of this year?

Well, from our standpoint we always focus on acquiring the strategic acreage that is going to be developed quickly. So in this quarter you could see that we added over 12,000 acres of new acreage, and a majority of that acreage was either permitted or in an approved drilling spacing unit in North Dakota and Montana. From a standpoint we will generally benefit just across-the-board from the increase in pressure pumping crews from that metric, but we track net spud wells, net well spud during the year more closely than anything else, and we will just benefit across from the board from the increased number of frac crews.

Okay. Really appreciate it, guys. Thanks for all the color.

Next up is Josh Silverstein, EnereCap Partners.

Hi, guys. That was similar to my first question which was are you seeing a trend of your ability to be able to pick up new acreage that is permitted or currently under the bit, and is that costing the same or is it costing more to try to get in on that acreage versus acreage that might have a longer leasehold?

Josh, thanks for the question. The trend has always kind of remained the same. I mean our typical methodology has been to acquire in the areas of production when we have clarity on when an area will be developed. Whether that's six, 12, 18 or 24 months out. That is generally the nature of acreage that we have been acquiring over the last year or two, so we try to target those interests. There are in many cases a disparity in sort of a pricing differential between acres that will be developed in a very short timeframe versus an intermediate or longer timeframe, and we put that all into the formula and when factoring what we think the acres are worth. So we try to build aportfolio that has a mix of different timing, such that the development isn't all coming in one block, that it is spread out appropriately, and we are allocating those dollars correctly.

Got it. And then was there an area or county where you were really adding most of the acreage this quarter, or was it kind of spread out amongst most of your acreage holdings in North Dakota?

Generally, Josh, it has been across-the-board. I mean if you look at the map we have up on website there is no real area that we concentrated in. There are new areas that have become more exciting, down to the south, down so the west, and we will naturally be drawn into the areas where there is more opportunity but I wouldn't say there was a specific area we were highly focused on in the second quarter, really from north to south, east to west, across the delineated area which is the real key. We don't believe we are buying acres out in front of the path of development. We believe we are generally following behind the path of development, with a high degree of certainty that the acres we are buying will be developed.

Got you, and I know the question was asked previously regarding the stock buyback. I was curious if there might be any sort of update as to you guys issuing some sort of senior debt or long-term debt in order to facilitate buying back stock, if you think that your stock still represents some of the cheapest acreage out there?

Well, we believe that as far as our capital position in the markets we can accomplish anything we are looking to accomplish from the drilling acreage and stock buyback perspective under our credit facility. We have puts the mechanism in place to be able to bump that facility up to $500 million and looking at the models that you all have for cash flow this year and next year, into 2013 you can see that we don't outspend our cash flow by any meaningful amount. So we think we retain a significant amount of flexibility under our credit facility, to execute the buy back, to continue to acquire acreage, and to meet our drilling obligations. So as of right now we have no plans to issue any additional debt.

Great. That is it for me.

Thank you, Josh.

Our Marty Beskow, Northland Capital Markets.

Could you give is some guidance for G&A expense for third and fourth quarter this year?

Marty, you should see the numbers remain pretty consistent with what you saw here in the second quarter. With call it maybe a 10% variance. We don't see any meaningful bump or meaningful change either way.

And how about as far as your headcount, how has that changed from what it is now to what it was the last couple quarters?

Well, we have about 13, actually 14 employees right now. There are a couple of additions that we are working on. You will probably see that heads count climb by another two to four over the next quarter to two quarters, just as we continue to ramp up production, and add some more in-house functions. You won't see it double, or go haywire from here, but I think it is reasonable to assume you will see it increase one to two people a quarter over the next few quarters, as we get ourselves up to full speed, and backfill into some of the capabilities that we will now have here in-house, as opposed to outsourcing. As the operations get a little bit bigger it makes more sense to bring some things in-house, and what we are essentially doing is swapping externally sourced assets for the same functions in-house. So you shouldn't see a big change to the G&A number.

Okay. And how about as far as did you have the reserve report done mid-year?

Well, what we have left to do, Marty, is work on the reserve report as of July 30th. We had such a backlog of wells that were completed in the month of July , that we wanted to be sure to capture those. So it is our intent to add another month, and what we are hoping that within about three to four weeks we will publish that full reserve report. We weren't required under our credit facility to update our reserve report. We had plenty of room there, so we wanted to make sure that we included those July production additions into that reserve report, and I would like for that from us in the next three to four weeks, and what we will do public is publish the entire reserve report for everyone to review, that should be a very good representation of what our proved and reserved value is right now.

Okay. Great. Thank you.

Next we will hear from Brian Velie, Capital One Southcoast.

My question has actually already been answered. Thanks, guys.

Next up is a follow-up from Marcus Talbert, Canaccord.

Hi, guys. Just one quick follow-up here. More particularly for Ryan. How are you thinking about I guess from sort of a macro perspective it seems like you guys have been pretty astute hedgers thus far, with the tape in the past couple of days. Any thoughts or actions that you guys are thinking taking into the second half of this year?

Yes. Thanks, Marcus. I mean we are very pleased with the hedges we have in place right now. We have always sort of employed a few internal rules. We generally like to stay between 50% an 65% hedged in the current year, 25% hedged looking out into the next year, and then rolling that forward on an incremental basis. We are very happy to hedge oil in the 90s and high-80s, where we have been hedging it. We are very secure for the balance of 2011, and very secure into 2012 with our hedges. So we are very protected from a cash flow standpoint, and our hedging decisions have been driven more by trying to match up the surety of our cash flows versus our development needs, as opposed to sort of gaining or making a macro call on the market.

I mean our leverage to oil prices is very great to the upside. I have mentioned many times that if we are 50% hedged at $100 oil, we will probably be 35% hedged at $120 oil, because you will see production ramp up, activity ramp up, and more production coming online. Conversely, if we see oil prices drop, and we see drilling activity slow down, then therefore, we will have a larger percentage of our production hedged. So we are generally going to stick with that plan at least through 2012 and into 2013. As we are building the cash flows behind us that allow us to develop into the future, and become substantially free cash flow positive. Until we get to that point we want to make sure we retain that flexibility, and are able to get through any kind of volatility we see in the commodity markets. And get this position held by production.

Okay. Great. And we have heard a couple of guys talking about tightening differentials. Is that something that we should sort of think about for the third and fourth quarters differentials from Clear Brook and other alternatives that you guys are experiencing, or the operators are experiencing?

Well, we have definitely seen differentials tighten, I think quarter-over-quarter our differentials tighten by about two bucks or so, and as long as you see the Brent WTI spread continue just where it is I think it is north of $20 today, $22, you are going to continue to see that differential tighten. You may see WTI become less relevant as a benchmark as there are more transportation options that are going to allow us to receive Brents or LLS pricing benchmarks, and so certainly as production in the field has continued to ramp up differentials historically have been a concern.

And as long as we see the WTI Brent spread where it is, differentials won't be a concern and I think likely you will see them tighten. It is going to be impossible really to predict where they go, but I do know that at the current WTI Brent spread levels it is very economic to move these barrels via rail, and those rail shippers are making tremendous margins on the barrels they are shipping. So that has turned into a fantastic business, and that should provide us very solid floor in differentials even as we see production ramp up substantially.

Okay. Appreciate it. Thanks again, guys.

Thank you.

And gentlemen, that is all the questions there are in the queue today. Ladies and gentlemen, that does concludes today's conference. Thank you all for your participation, and have a great day.