Oasis Petroleum (NYSE:OAS)
Q3 2010 Earnings Call
November 09, 2010 10:30 am ET
Michael Lou - SVP, Finance
Tommy Nusz - President & CEO
Taylor Reid - EVP & COO,
Roy Mace - SVP & CAO
Richard Robuck - Director of IR
David Kistler – Simmons & Company
David Deckelbaum - UBS
Ron Mills – Johnson Rice
Andrew Coleman – Madison Williams
Michael Hall – Wells Fargo
Derek Whitfield – Canaccord Genuity
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 area. At the end of the quarter, we had 270 million of cash and 120 million available under our revolver. So we're well capitalized for future execution on our operational plan and future growth.
Along with our operational results we also announced an acquisition transaction that will help us to continue to improve operational control over one of our large contiguous lease blocks. As most of you know from our company presentations and previous conversations, Oasis had an AMI in our West Williston area in a project that we call Hebron located in Roosevelt County, Montana, just west of the North Dakota border. Before the deal we had approximately 17,000 net acres that we did not operate with an average working interest of about 50%.
The seller and then operator had drilled two recent 10,000 foot lateral wells, both completed with 23 plug and perf frac stages. Both of those wells, the Luke Sweetman and the Amazing Grace looked very encouraging based on early results and have gone a long way in helping us delineate the acreage. In fact, these wells are already performing within our EUR band for West Williston at 400 to 700,000 barrels of oil only. As a result, we believe this area to be highly perspective and accretive to our long term growth potential.
Last Friday, we closed on that acquisition of 16,700 net acres in Hebron giving us operational control and bringing our total net acres to approximately 34,000 in that project area. The price we paid at close was approximately $50 million which includes the acreage and production of about 300 barrels of oil a day equivalent net to Oasis.
In order to exploit this area we have contracted a sixth operated rig that will ultimately be dedicated to run continuously in this project area. We expect our increased operational presence and activity in Hebron will drive further operating efficiencies across the field, further driving down per unit cost.
Michael will spend a little more time walking through the overall impacts of this acquisition to our capital budget and liquidity later in the call.
We are continuing to employ a base well design that consist of approximately 10,000 foot laterals and 28 frac stages. Like we said in August, we are seeing well cost in the $6.8 to $7.2 million range for a 28 stage plug and perf well. Although we believe those cost would be even higher if not for the ongoing efforts of our operations group to improve cost efficiencies. Despite the fact that rig count in the Williston is now just under 160, which we believe is an all-time high, service cost are starting to moderate a bit and availability is improving.
As we've discussed previously, to help us manage cost and efficiency as well as ensure the timely completion of our newly drilled wells, we've entered into agreements with two pumping service providers to secure sufficient capacity to support a five to six rig program.
We have one dedicated crew that will be able to do four to five wells per month and the other provider picks up one slot per month. We are also talking to a third company that has the ability to provide additional capacity. So our guys have done a great job of securing quality services and we're comfortable that we will be in good shape to match our drilling program with frac slots as we enter into our 2011 program.
Our typical well includes 28 stages with a 65/35 split between ceramics and sand, and we believe this setup gets us into our economic type curve range. Still, we continue to vary completion techniques to optimize our economics in different areas that we operate. So that includes increasing the number of stages as well as optimizing proppant type and optimizing delivery systems. We have also been tweaking our per stage concentrations.
While still early, we feel very good about our continuous improvement efforts on completions. We continue to increase our confidence in 28 stages as a baseline with little to no dilution in per stage recoveries. So we're now playing with some increased stage jobs and believe that additional stages above 28 will deliver accretive economics. In fact, that is likely to be the most efficient capital we spend.
We have recently completed the Ernst well on our East Nesson block on the northern end of that core area up in Burke County. This was a 25 plug and perf plus 11 sliding sleeve combination. Again, early days, but it looks like we’ve moved this well further up into our type curve range for the east side. We pumped over 5 million pounds of white sand and completed the well at a cost of just over $6.2 million. The performance results of our recent wells are still early, but we do not have anything that would lead us to believe that we aren’t taking the right steps to improve overall well economics and per well recoveries across the basin. Other operators might use different variations on their completions but ultimately more data points are great for everyone. As we get more results from different completion techniques, we'll use the best available data to make the best decisions on future wells.
With our 1033 net potential locations in the Williston, this early work can definitely have a big impact across our inventory. As we’ve discussed previously our multi-year inventory of operated drilling projects on our large concentrated acreage position gives us long-term growth visibility and time to work constructively with our service providers to find efficiencies and manage costs.
With the Hebron transaction complete Oasis has now over 300,000 net acres in the Williston Basin. In our West Williston project area we are estimating the gross reserves ranging on average between 400 and 700,000 barrels of oil only or 450 to 790,000 equivalent. We expect that a portion of our inventory in the West Williston is resilient to lower oil prices in the $45 to $50 WTI range, given current cost structure. Specifically, this is the area around our operated Angell well which is just south of the river on the east side of our West Williston position.
We also recently completed the Kjorstad well on the north side of the river just above the Angell and early results look very good with the first seven day average of 1670 Boes per day in line with what we saw out of the Angell well. This further confirms the resiliency of this position and the production from the Kjorstad will show up in our fourth quarter numbers.
In West Williston, we have increased production in the third quarter to 2327 Boes per day, a 57% sequential increase over the prior quarter. This increase is driven primarily by our operated drilling program. Note that results from the acreage acquired in our Hebron acquisition will be reported as part of the West Williston project area going forward.
We’ve got a slide in our latest presentation that shows you specific geography and highlights associated with that transaction. And East Nesson we are maintaining our gross reserves average between 350 and 600,000 barrels of oil only or 400 to 675,000 equivalent. Although this area is still in early stages of development our east side wells within our core area look to be within our expected EUR range closer to the mid to the high end in the southern part of the block and lower end to the northern part of the block.
We believe the acreage in the Southern Burke county works well especially with early results on the Ernst well which, as I mentioned earlier, was completed with over 5 million pounds of white sand across 36 stages at a total cost of $6.2 million. Early performance is clearly in the range on the Ernst Well which produced at an average 441 Boes per day with the first 60 days.
As we’ve said before, the lower EUR range on East Nesson relative to West Williston is due to lower reservoir pressure with shallower depths as you head North in the East Nesson Block. As well as higher water saturations in more variability in water cuts. Our Sanish area wells are all non-operated as you know but very prolific.
Our production in the third quarter increased to 1445 Boes per day or a 6% increase over the prior quarter. In this area we have a working interest that range anywhere from less than 1% to as much as 15% and 1.4 net wells came on production in the third quarter in our Sanish position. I will now hand the call back to Michael who will review our financial results.
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 to $1.6 million or $7.70 per Boe in the same quarter last year.
Higher general and administrative costs in the third quarter were largely the result of onetime costs associated with our IPO, the increased cost of being a public company as well as hiring more employees to support and manage the growth of the company.
In the third quarter, we increased our estimate of our deferred tax liability associated with the corporate reorganization we entered into at the IPO by $6.2 million to $35.4 million total. This was obviously non-cash and given our current tax loss status and expected pace of drilling, we do not expect to be a cash tax payer this year.
Our capital expenditures in the third quarter were $74.8 million bringing our year-to-date capital expenditures up to $183.3 million. Of our year-to-date expenditures approximately 53% of our capital budget was invested in our West Williston project area, 36% in the East Nesson and 11% in Sanish.
In the first nine months we have deployed 85% of our capital dollars towards the drillbit consistent with our philosophy to focus our capital on our drilling plan. On November 4, our Board of Directors approved an increase in the company’s 2010 capital budget associated with the recent acquisition of the Hebron assets. Our updated capital budget for this year is $328.5 million which includes the acquisition of $49.9 million as well as an increase associated with the drilling and completions of the newly acquired acreage.
We provided updated guidance for 2010 in our press release which include our Hebron acquisition and updates to where we see our numbers for the year. We raised our fourth quarter average daily production guidance to 6,000 to 7,300 Boe per day. The increase is primarily a result of stronger than expected performance from our operated and non-operated wells and the additional production acquired in our Hebron transaction. We lowered our annual LOE guidance range to $7.25 to $7.75 per Boe. Our team has done a great job managing cost with year-to-date LOE costs of $7.54 per Boe. And as Tommy mentioned earlier, LOE costs continue to head in the right direction.
As it relates to G&A expenses, we are expected to be between $9 and $10 per Boe. This guidance is up slightly from the August guidance numbers for several reasons. First we have had some additional IPO costs and expenses associated with being a public company that are a bit higher than projected. Second, our headcount has increased a bit more rapidly than originally anticipated due to our capital plan increases.
We’d also note that as a private company, we did not accrue for bonus expenses throughout the year. So 2010, that expense will hit our fourth quarter, it will likely be higher than anticipated due to higher headcount than planned in operational over performance versus the plan.
In 2011 we may revisit this protocol and we’ll consider accruing for bonuses throughout the year. As per guidance for 2011 we are currently going through a five-year plan and 2011 budget review which we will present to our Board in mid December. We plan to announce our 2011 budget as well as 2011 guidance after this review.
Finally, we finished the third quarter with the cash balance of $270 million and no debt. We also have an undrawn revolving credit facility of $120 million. Given our cash position, expected cash flow, and undrawn credit facility, we have adequate liquidity to fund our future capital commitments and development drilling programs.
I will now turn the call back to Tommy for some closing remarks.
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.
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.
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