Good morning, my name is Monica and I will be your conference operator today. At this time I would like to welcome everyone to the third quarter earnings release and operations update for Oasis Petroleum Incorporated’s 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) Mr. Lou you may begin you conference.

Thank you Monica, Good morning everybody. This is Michael Lou, Senior Vice President of Finance. Many thanks for joining us today as we discuss our third quarter results. Joining me today, are Tommy Nusz, President and Chief Executive Officer, Taylor Reid, Chief Operating Officer, Roy Mace, Chief Accounting Officer and Richard Robuck, Director of Investor Relations. During this call we will provide more details about the acquisition that we announced last night, review our results for the third quarter and then discuss the outlook for the remainder of 2010. This conference call is being recorded and will be available for replay approximately one hour after its completion. The conference call replay and our third quarter 2010 earnings release are available on our website at www.oasispetroleum.com. In addition, we have updated our investor presentation for November and it is on our website. Although we will not be speaking off the slides during this call, please feel free to refer to it for clarification. Please be advised that our following remarks, including the answers to your questions, include statements that we believe to be forward looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission, including our Form S-1 and as amended. We disclaim any obligation to update these forward-looking statements. Please note that our third quarter 2010 form 10-Q will be filed tomorrow. During this conference call we will make references to adjusted EBITDA which is a non-GAAP financial measure. Reconciliations of adjusted EBITDA to the applicable GAAP measure can be found in our earnings release or on our website. Since our last call in August we continue to execute our plan to aggressively develop and capture our Bakken acreage. We have maintained our focus on drilling in our core Williston Basin areas, expanded our growth potential and improved our ability to control operations. We are extremely excited by our record quarter and the outlook for the company. I will turn the call over to Tommy Nusz.

Thank you, Michael and good morning everyone and thank you for joining us today for our second earnings call as a public company. Third quarter can be quickly summarized by the following. First, financial results are positive with volumes growing and LOE moving in the right direction. Second the capital plan is on track with recoveries in line with expectations and costs under control. And third we are continuing to high grade our acreage position and build on our core operated acreage blocks. Last night, we issued a news release discussing some of our financial and operating highlights for the quarter and year-to-date ending September 30, 2010. Like last time, we will try to add some color to that release and update you on our plans for the rest of the year. Then we will open the call up for Q&A. As you know, Oasis became a publicly traded company on June 17 of this year. The stock trades on the New York Stock Exchange under the ticker OAS. The IPO provided the capital and liquidity for our seasoned team to execute on our long-term growth plan which is increasing production and reserves and ultimately net asset value for our shareholders. We have delivered continuous production growth since early 2009 and that trend continued in the third quarter. Specifically in the third quarter, we brought eight gross operated wells on production and have 12 more wells currently drilling or waiting on completion. Including operated and non-operated wells, we added 7.3 net wells in the quarter and increased overall average daily production to 5,507 Boe per day, up 149% year-over-year and up 23% over the previous quarter. Overall we expect recoveries for our third quarter wells to be within the type curve ranges that we have previously laid out for each…

Thank you Tommy. Based on our earnings release you can see that we posted several records which we are very excited about. First our adjusted EBITDA reached $22 million for the third quarter which was a $15.5 million increase over the third quarter of 2009. Also, we had another record quarter on production which Tommy discussed earlier. As I don’t expect anyone on the call wants me to reread our press release, I'll just provide some color on a few points that need some elaboration. We had a realized price for oil of $66.42 per barrel in a 13% differential in the third quarter. Historically the basis has been about a 10% average differential and we started the year with differentials at 11%. In the second quarter there was a bit of additional pressure on the takeaway side due to a scheduled five to six week turnaround at the Tesoro-Mandan refinery which pushed differentials up to 14%. We saw that differential narrow in the third quarter up until the time the Enbridge six day line went down. The differential did start to expand again but this was slightly offset by higher NYMEX prices which rose at the same time the line went down. So while realized prices stayed relatively in line, the dollar differential definitely grew at that time. Lease operating expenses for the third quarter were $6.33 per Boe a 38% decrease per Boe from the third quarter of 2009. The main factors driving this improvement were increasing oil production volumes with a higher proportion of our production coming from Bakken wells reducing the impact of our higher cost Madison formation wells. Our Bakken wells are more productive and cost efficient than the older Madison wells. General and administrative cost increased to $4.8 million or $9.57 per Boe compared…

Thank you, Michael. We continue to aggressively and cost effectively grow production and reserves and maintain a large inventory of high graded drilling locations. The team is employing leading drilling and completion techniques to maximize returns while preserving the strength of our balance sheet. Lastly, we are continuing to grow our net asset value to our shareholders. The Hebron transaction is in line with how we expect to manage our acreage and our desire to drive operations. We roughly doubled our acreage in Hebron to approximately 34,000 net acres and converted a non-operated area to an operated area on a large contiguous block of acreage, enhancing our ability to generate operational efficiencies and manage costs. As the operator, we will control the pace, design and cost of future wells on that acreage, using the best practice completion techniques we employ in other areas which we believe will result in EURs very similar to our West Williston wells. As I said last quarter I remain confident about our ability to achieve our growth potential because we have the right people, quality assets in the right spots, and a tremendous oil resource play and the financial resources to execute on our plan. Now we'll go ahead and open the line up for questions.

(Operator Instructions) And your first question comes from the line of Dave Kistler.

Real quickly focusing on the Hebron acquisition, you mentioned how LOE comes down as a result of the integration of a play like this. Can you speak specifically, not on a companywide basis, but just on the impact of adding this kind of acreage, what it does just say the 17,000 acres you have there in terms of reducing the cost or am I getting too specific on that?

You may be getting a bit granular Dave, but keep in mind what we said consistently is that our Bakken production will be generally somewhere in the 4 to 5, maybe $6 range per Boe. We have got that existing Madison production which is about 800 barrels a day net roughly. So the more we do, we continue to loop down and that’s part of what's driving the decrease in our LOE as we go through quarters.

And then maybe hopping over to the acreage around the Angell well where you talked about it being very sustainable at kind of $45 to $50 oil prices. Can you just talk a little bit in terms of how much acreage you think is viable for $45 to $50 oil and then maybe as you look at this, does this ultimately cause you to delineate the play differently and maybe start creating type curves for different areas?

Couple of things I would say, the area directly in and around the Angell well and the Kjorstad well is about 24,000 net acres, that’s out over on the west side and in total we have got about a 190,000 acres, the nice thing about that is that if in the event that we do have softer commodity prices it gives us some where to take rigs that we have already got contracted back to a spot that’s very resilient at those low oil prices. And then your second question was?

With really given that you have an area that obviously is a little bit more economic, would you ever consider starting to delineate the play with different type curves?

Yes I think right now we have been delineating between east and west for you guys and I think as time goes on, we will be able to give you a bit more granularity on that, we do kind of at a high level for instance on the east by saying that the southern wells are closer to the higher end and northern wells are closer to the low end. Same thing on the west side obviously as we’ve talked about before that area in and around the Angell and the Kjorstad seems to be a bit - the Angell well specifically producing at or above the top end of the type curve. So overtime I would expect to be able to give a bit more granularity on pods and associated well costs which will always be important, we will start to expand that range with per well costs a bit and as we get more data we will be able to give you more feedback to match that up with well recoveries by pod.

Great that will be helpful and then just one last thing you didn’t really address it and its hard for you to address at this point given that you are drilling wells that are relatively far apart from each other, but listening to other conference calls, sharing information, any new thoughts on down spacing and how you guys are thinking about that going forward.

Taylor do you want to take that?

Yeah, we are still looking at it, so for the Bakken, for example, three wells per spacing unit, we are looking at results from other operators the area – the area you got most data at this point really is Sanish and you are seeing the move to three wells and certainly in the Bakken and some of the operators talking about two to three additional wells in the Three Forks. So we follow all that data and think it’ll apply to other parts of the basin and so at this point we are feeling pretty confident it’s probably three per spacing unit and continuing to work on it.

And your next question comes from the line of David Deckelbaum.

Just wanted to know if you could expand a little bit on a talk around the down spacing, when you look to 2011, when should we expect to see sort of a Three Forks test from Oasis?

I’ll let Taylor jump in. It’s a couple of things. One is on infills we probably in 11 probably second quarter-ish try to do some infill testing but it will probably be in adjacent units, the Brigham guys touched on that a bit the other day where we can continue to work on our plan to hold our drill blocks but test infill potential by drilling close spaced wells in adjacent units and then in the Three Forks, I think also we are still finalizing our budget plans for next year. We will have all that done in December but I think sometime second quarter. Taylor, on Three Forks?

Probably end of next year having 3 to 5 Three Forks wells in the west side- still working on the plan like Tommy said but somewhere in that range and first one will probably be in the second quarter.

I guess on the Hebron acquisition real quickly and I don’t know if I missed this but what’s your working interest in the acquired acreage?

Post acquisition, we are going to end up with a pretty high working interest. I don’t know what the exact numbers are but I would guess on a per-well basis, we are somewhere in the 80% range.

80% range on the operated blocks, so we picked up half of the interest.

It was a 50-50 AMI to begin with, so we have basically doubled our position and our working interest on a per-well basis should be somewhere in that 75 to 80% range.

I know you guys have talked in the past a lot about consolidating some of the unfilled areas that’s surrounded by your acreage, can you talk a little bit about what sort of should we be looking forward to seeing similar acquisitions to this in the near future, should we? How does that relate to how you’re thinking about holding the rest of your acreage in other parts particularly in East Nesson?

The highest priority for us and we have said this consistently, is preserving the quality acreage blocks that we have and not running out and doing deals that dilute our focus on that objective. This was a great deal for us because one, its leases that we already have the remaining 50% in plus we can take over operatorship which we felt was important and so where we’ve got the opportunity to continue to do that we will and now again we got to balance that off against aggregate lease preservation within the context overall of our capital liquidity and as we’ve said before trying to get to end of ‘11 with a clean balance sheet. Now, as we do deals like that, that may pull that up a bit but probably not outside of the resolution of our ability to estimate our cash flow with oil prices and then getting into 2013 with a balance of cash flow and CapEx. So still focused on that and we have to be mindful of it aswe look at incremental deals but in our opinion where we are adding value in these large contiguous blocks we will continue to look to consolidate. We’ve said that consistently.

And your next question comes from the line of Michael Hall.

Just a couple of quick ones from me. As I look at the wells, weighing on completion relative to wells drilled currently 4.9 waiting was 2.8 drilling? Is that about the same ratio you would typically want to run as I am kind of thinking forward?

Michael what I would say is that our spud to first production is still running just under 90 days and that is what we are focusing on. We had a bit of a backlog here but we are working that, in fact we were fracing three wells yesterday. So our plan is to stay up with our completions and again focus on reducing our spud to first production time of 90 days and we are still right now just under that and as we continue to work in these large blocks with adjacent wells, we ought to be able to drive that efficiency down more – cycle times.

Okay that is helpful so I mean it is just kind of a timing issue in terms moving equipment from place to another as opposed to any availability issue is that?

We don’t just, we don’t have a problem with availability like Tommy said we did have a little bit of a backlog and we really worked that down. We are getting close to the point of what we call balance going from drilling wells and to fracing them.

Okay and then as you evaluated the Hebron acreage is there any credit being given to Three Forks as you looked at that deal or is it purely evaluating this Bakken acreage at this point. How did you think about that I guess?

For us while we think the Three Forks is prospective there and we’ve said that consistently it is difficult to break out by component exactly what you paid for what in the $50 million but clearly we see that as an upside and we’ve said that consistently.

And your next question comes from the line of Ron Mills.

Couple of questions, you talked about the Ernst well up in Southern Burke County, was that the well that you said averaged 440 barrels a day over the first 30 days?

Its 441 barrels a day over the first 60 days.

Over 60 days. And I know you had let in the second quarter some acreage expire over on the East Nesson area and you picked some up in West Williston. You also had an impairment charge this quarter. I'm assuming, can you give us a little bit more color in terms of acreage expirations versus acreage additions this quarter or even if you want to include the Hebron deal?

On our base acreage position, I think we ended up net-net, loosing about 2,300 acres, I think we lost 4,000ish or 5,000 and picked up about 2,500, about half that much and our impairment charge was pretty low, Roy you have that number?

It was about $800,000, about 816.

And then as you look at the activity, you obviously have four rigs at West Williston, one at East Nesson and one going to Hebron or I guess if it’s not already there, you talked about adding a seventh rig next year, is the plan still to have that one target the West Williston?

Yes, I don’t know if the guys have updated the plan yet, but basically, I think its still going to be one on the east and then the remainder of the rigs on the west. We may as we bring that one on, we may catch a couple of locations in the east before sending it over, but basically I think the way to think about it is still one on the east and then six on the west when we get to seven.

Yeah, at this point. Later in the year we may pick up a few more wells on East Nesson before we take them to the west side.

And Michael you talked about the price differentials from 11 to 14 to 13%, you had the Enbridge issue obviously impact the third quarter. Where are those differentials running right now versus that third quarter average of 13%? Because I think as of the August call you always gotten back in to plus or minus 10 or 11% range prior to Enbridge, trying to get a run rate going forward?

Yes we are still currently running kind of in that 10% to 15% range, its changing but that 13% neighborhood is probably still pretty good for right now.

Okay. I guess one last one that you mentioned, Tommy, I missed it I think, you talked about getting into 2013 with cash flow and debt which in terms of liquidity situation even with this acquisition what were you were talking I missed your comment right before that, were you talking about between your cash flow and availability to get you into 2013 or was there an interim step in there as well

Ron, what we've said consistently is, is that trying to get out to the end of 2011 with zero debt. We got a gap in 12 that we would probably fund with some type of high yield and then bridge us to ‘13 where we get back to balance. Obviously with, spending another $50 million on this deal then that may in ‘11, that may accelerate that debt a little bit but we can’t to try to predict exactly when that’s going to happen relative to market condition is difficult but it may. I mean logically as we model it obviously it would pull it a little bit forward. That being said, we may be able to do a little bit more than what we thought that we could do on the debt side originally with results plus increasing PDP. So still have that as a goal and will keep you guys updated on where we think we are relative to that goal and make the best financing decisions relative to our ongoing activity and how we are adding value.

And your next question comes from the line of Derek Whitfield.

In thinking about your completion testing to date, are there any generalizations you guys can make about the other variables outside of stages?

Some of the other things we have been looking at in addition to the number of stages is the concentration, proppant or pounds per stage and generally see a increase in recoveries as you increase the pounds pumped per stage. We are also working on delivery methods so type of fluids you’re pumping. For example, one end - heavy crosslink fluids to lighter fluids like slick water or the mix of those two.

We did a bit of it, as I mentioned we did a combination on the Ernst well which was plug and perf and sleeves but the guys are getting good enough at this now to where we are doing seven or eight stages a day. So, on the plug and perf, so we are getting pretty efficient at that.

But we set up a program of test wells in and around our standard 28 stage frac wells. We've got a set of control wells and then some of these wells that we are trying new stimulation types. As we get enough production data, we will make some adjustments to the stimulation program going forward. Our standard is still the 28 stage frac.

Taylor, outside of stages, does it feel like proppant concentration or maybe pounds per stages is one of the most important variables?

We're still looking at it but it looks like there is a pretty decent correlation.

Moving over to gas infrastructure, could you guys comment on how long it's taking you now to get your gas connected to sales?

In our areas we got limited infrastructure still so on the west side on Red Bank we don’t have any wells currently tied in. We have signed an agreement in that area with Hiland, and they are currently designing and putting in the pipe and all that will go to a plant that they have that is south of that area that’s also under construction. We expect the gas from both the Red Bank and Indian Hills area which were both with Hiland, beyond in the third quarter of next year. We got a few wells that are tied in the Indian Hills but for the most part, there's not enough infrastructure in that area as well. We’ve got a mix of wells on the south end of the east Nesson, currently new wells that are tied in and we are working on arrangements with parties in that area. We are hoping to have our wells on the east side tied in by late next year early the following year, the remainder of them.

And your final question comes from the line of Andrew Coleman.

I had a question for you about, your type curve looks like its 88% oil and I assume are there NGLs included in that or is that in the 12% that would be on the gas side?

Its two product, not three

Which is the oil and gas.

Yes.

So I don’t have to worry about forecasting an NGL price then for the quarter. When you say two commodities there, you talking gas and oil or you talking about oil and NGL?

Yes, ultimately the way you can think about it there will be, the way the contracts work on the gas side, we do get credit for NGLs and gas but a good way to think about that’s easier is you can take the gas volume that you're going to get NYMEX plus, pretty close to NYMEX by the time you have worked through the gas price, NGLs and get back to the NYMEX pricing.

And then lastly just coming back to the G&A, the accrual for the fourth quarter, you guys haven’t put out a number you think that that might be for the fourth quarter. I was looking through the release, I didn’t see any guidance for that.

We haven’t specifically said what that number is obviously it is something that we will reviewing with our Board, the performance for this year with the Board in December and it will be a number that they will determine for us.

Okay all right, cool. And I'll just look at it for the short term as something similar what the implied run rate was on a percentage basis fourth quarter last year.

And at this time there are no further questions. We will now turn the call back over to Tommy for closing remarks.

Thanks again for everyone’s participation in our call this morning. Obviously we are very excited about our progress to date in the business and look forward to updating you on our progress again next quarter. Thank you.

Ladies and gentlemen this does conclude today’s conference call. You may now disconnect.