Good morning. And welcome to Kodiak Oil & Gas Fourth Quarter 2013 Financial and Operating Results Conference Call. All participants will be in listen-only mode. (Operator Instructions) After today’s presentation there will be an opportunity to ask questions. (Operator Instructions)
Please note, this event is being recorded. Now, I would like to turn the conference over to Lynn Peterson. Mr. Peterson, please go ahead.
Good morning, everyone. Please be advised that our remarks today, including answers to your questions, includes 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 financial and operating results, news release issued yesterday and in our filings with the Securities and Exchange Commission.
We disclaim any obligation to update these forward-looking statements. While the company believes these forward-looking statements are reasonable, they are subject to factors such as commodity prices, competition, technology and environmental and regulatory compliance. Our drilling schedules, capital plans and other factors may cause our results to differ materially.
Okay. Good morning everyone. We have passed that so. Welcome to the call. Again, please reference the news release and our filing on Form 10-K both of which were made available last evening for further details and full disclosure topics we’re going to be discussing today.
2013 was another successful year for the company. We delivered outstanding production and reserve growth, grew the size of our asset base both organically and through acquisitions, and continue to be one of the industry leaders and proving out downspacing in the basin, which ultimately lead to additional organic growth and drilling inventory.
I know each earnings season takes its toll on everyone as numbers and results are put under microscope and dissect it every way possible. In an effort to make this call more beneficial to our listeners, we're going to change our format this morning and not regurgitate all the numbers we have ousted over the last few weeks. We will be adding an earnings supplement to our corporate website that summarizes all of the key financial and operational highlights for the last three years. I trust that you can look to slides, so therefore I am not going to take up more of your time and discuss some again.
Instead we are going to try to comment on some of the more important developments in the Williston basin and address frequent topics of conversation that we have with our shareholders. I have asked several members of our management team to join me this morning and present information to our listeners so that you can hear some different voices from the company.
As transportation [inaudible] hot topic, I am going to turn the call over first to Bruce Taton, our Vice President of Marketing.
Thanks, Lynn. Good morning to everyone. Kodiak is currently selling the majority of its crude oil production directly to refiners, or companies with dedicated supply agreements with the refiner. Approximately 65% goes to refiners with the remaining 35% going to various purchasers. Approximately 80% of the January and February volumes were moved to rail facilities with 20% moving on pipelines out of the area.
We’ve been successful in committing volumes on a month-to-month basis with assurances to the purchasers that Kodiak will supply barrels each month. This has enabled us to move oil production with no interruptions. So far there have been no issues with capacity into these markets. In January and February we estimate that approximately 40% of our oil has moved to the East Coast Brent market, 15% to the West Coast market, 20% to the Gulf Coast LLS market and the remainder split between [Clairbrooke and Guarantee] Wyoming markets. With our sales to Tesoro, some volume ultimately ends up at their Mandan, North Dakota refinery.
We're watching carefully the developing rail issues. While at this point we can’t be certain as to new regulations, we expect the issue will be resolved and any new regulations will be made and we will continue to move via rail. From what we hear, there is certainly will be increased costs associated with new regulations but we do not expect these costs to be material to our pricing, and in the end we all want to see oil move safely independently.
We’re pleased with our alliances and relationships with the markets and companies involved in sourcing Bakken oil. We believe that due to these alliances we can move forward with our development plans without concern for capacity restraints. We’ve seen continued interest in Bakken oil because of its high quality and ability to deliver to multiple downstream markets that have historically relied on more expensive imported oil. We think this will continue as evidenced by plans to increase deliveries to California and Canadian refineries. In addition, there are several pipelines in the works, most immediate upon the conversion of Home Express [ph] which we will start up later this year.
With transparency in the market, we feel we are capturing fair value for our oil without having to spend capital on pipeline space, railcars, or proprietary trucking. That being said, we're always looking at new proposals for pipelines and other means to move oil to markets.
In the fourth quarter, our realized price was approximately $12.50 per barrel below to WTI prices for the quarter. We will see improvements to that in the first quarter and are expecting something in the high single-digits. Our 2014 budget incorporated $10 barrel differentials for the full year and we believe that is probably still a pretty good target.
Closer to the wellhead, I should point out that approximately 85% of Kodiak’s oil is gathered into pipeline systems, eliminating most weather-related issues with moving the products. We’ve made progress during the last year in selling more of our associated natural gas production. Working diligently with our gas pipeline partners, we’ve improved our sales from 51% of produced volumes in January of 2013 to 66% over the same period of 2014. We continue to see the percentage grow as companies add more processing and compression capacities. It still remains a challenge to keep pace with our rate of growth.
Currently 92% of Kodiak’s producing mills are connected to gas gathering systems. Kodiak is in negotiations with various companies to build gathering in areas not currently connected.
We’ve also started the project to collect natural gas liquids at wells currently not connected to gathering. We expect to see more improvements in the percentage of gas sold as more expansion projects become operational in 2014.
Thank you Bruce and I hope that helped some of our listeners to understand how we view the transportation outlook for the basin. Next, I’d like to introduce Ron Finch. Ron heads up our completion operation. I have asked Ron to discuss results of our downspacing work and we’ll be looking to accomplish in the coming quarters. Ron?
Good morning everyone. I welcome the opportunity to speak to our shareholders this morning and share some of our thoughts. In 2013, Kodiak aggressively pursued the program to drill, complete and evaluate higher density lateral spacing which means more wells per DSU in the Middle Bakken and two Three Forks intervals in our core areas.
The major projects that appear to extrapolate across the core Kodiak acreage includes the two 12 well pilot projects in the Polar and Smokey areas that everybody has been exposed to before. A 6 well high density project including three Middle Bakken and three Three Forks wells within the standup DSU in the charging Eagle area of Dunn County.
The first pad of four wells -- excuse me the first pad of four wells in a 16 well DSU project directly east of the Polar pilot, that’s the 2.0 project that’s been referred to on the website. And finally, most of our drilling of our infill wells in our core areas is on a 600 to 700 foot spacing which will allow us to achieve higher density in each DSU as we go forward overtime.
Based on the initial results, Kodiak expects to significantly improve the EUR recovery factor from each DSU -- and additionally -- will be maximizing the net present value and dramatically increasing the overall well inventory across the acreage -- our acreage position.
The evaluation of the optimum lateral density for the Middle Bakken and Three Forks system is analogous to determine how many straws will be used to drain a Punchbowl when each straw cost nearly $9 million. It is a balance between acceleration of recovery versus the cost.
To date, the production from the Kodiak high density spacing project has been very positive. The production response in each area have been very similar to the offset DSUs with conventional two to four well spacing.
In addition to production compressions, Kodiak has used several tools to evaluate the effect of the increased lateral density that include reservoir simulation, login core analysis from the pilot holes, tracer studies, DFITs and micro seismic evaluation. The result of all this has been incorporated in simulation production -- in reservoir simulation and so far we have a positive match between a reservoir simulation and the actual production history.
While this timeframe, our production is only about six months long and while this time frame is still very early in the 30-plus year life of the wells, this initial work provides positive confirmation that the increased lateral density should achieve our goals to increase the early time rate with more straws in our Punchbowl, improve the overall EUR from each drilling spacing unit, optimize the overall recovery factor, maximize the net present value from each DSU and finally significantly increase the overall well inventory.
We have not fully quantified the potential impacts of our downspacing programs to our future drilling inventory but we do think it is fair to say that we have well over 12 years of identified potential future drilling locations assuming our current pace of activity about 100 wells per year without incorporating all the success that we have seen to date in the tighter well bore spacing units.
The current stage of development in the Bakken is probably similar to the early times of the Jonah and Pinedale Anticline fields. We believe that the ultimate development would probably result in even more higher density wells than we -- than are being considered in the pilot or experimental programs today.
While several challenges remain for the Bakken to achieve full development, we think that the upside from increased lateral density is tangible and achievable goal that will be realized by Kodiak over the coming years.
Thank you, Ron. We are proud of the work completed this past year as we continue to work on improving the ultimate recovery of the vast resource in the Williston basin. We’ve learned a lot about our assets but as Ron noted, we will continue to challenge our team to improve the recovery.
As usual, we caution everyone on making too many assumptions based upon early production numbers. Our early numbers on a recently released four-well [ph] pad were clearly within our expectations and these wells were put on to production during some pretty cold weather conditions.
Next, I am going to turn this over to Russ Branting. As you know, Russ is our executive vice president of operations and is largely responsible for managing our nearly $1 billion capital expenditure budget. Russ is going to share his thoughts on the basin as it relates to the operational efficiencies that we’re striving to achieve with ever-changing technological advances in drilling and completion.
Thanks, Lynn. And good morning to all our listeners. I would like to begin by giving you a quick update on the third party service environment in the Williston basin today.
A few years ago, when the service was really taking off [ph], third party services were few and far between and they were difficult to secure in a timely manner. We saw that [indiscernible] show up in operation. What a difference a few years has made? Today we believe the supply of available services in North Dakota we compete with any other play in North America.
We were able to contract spot completions in a matter of days instead of months, making it no longer necessary to enter into long-term agreement for our pressure pumping services. There are workover rigs and cold tubing units to service our wells whereas two or three years ago, they were almost impossible to come by.
Across the board, our operations are benefitting from a very good supply of manpower and equipment at the basin and we continue to look for qualified personnel. All of these developments have helped us realize a large positive impact in our well costs. In 2013, we saw our well costs decline by approximately 15% to 20% from earlier years. These cost reductions were achieved through the combination of service cost decreases and through field level efficiencies.
Currently our well costs, assuming a well in the deep part of the basin and completed with a 100% ISP, range between 8.7 million and 9.1 million. With additional efficiency gains and cost reductions, we hope to realize an additional cost savings of 5% as we move throughout the year.
In 2013, Kodiak operated 7 drilling rigs which drilled over 2 million field oil [ph]. In the world of billions and trillions, that might not seem like much with the same distances if you are walking from New York to Pittsburgh. We have seen a 16% decrease in our costs for PUDs in Q4, 2012 to Q4 2013. And our bare [ph] rigs are averaging 15.3 to 3D [ph]. The best two wells drilled to date are 11.5 days for 3D and our 2014, we will work on our consistency.
As our development needs have evolved, we are excited to upgrade our fleet with the addition of two new unit BOSS rigs in Q2 and Q3 this year. This is our new design AC drive rig resulting in high loads [ph] necessary to move the rig and this will translate into quicker rig move times and less costs. The new rigs will have a dual fuel capacity, so they can run green on natural gas. We are also permitting 8-well pads in our Polar area which with the addition of BOSS rigs and pump-up rigs, we should be able to drive additional efficiencies in our drilling operations.
On the completion side, Kodiak has seen efficiencies through performance management such as the zipper frac technique. This has decreased our average frac on from 7.5 days to 5.4 days per well. The record time so far is 2.7 days per well. The zipper frac technique also allows the optimization of water management.
An integral component of our business of servicing our wells, we have 4, 24 hour crews for running and pulling for our streams as well as 5 additional daylight only service rigs. This allows Kodiak to minimize our down production. We ended 2013 [indiscernible] gross production and once you remember that we ranked number 20 in 2010. We continue to and/or produce water more efficiently and we have increased our water gathering pipeline to 65% of the total daily volume. This has helped decrease our LOE as water handling disposal is one of the highest cost for a producing well.
We will continue to build out our infrastructure in 2014 with additional -- our salt water disposal wells and gathering systems. We're aggressively focused on replacing these diesel fired generators with green natural gas driven generators on our producing well sites. This should also drive down our LOE as fuel for generators of the second largest customer LOE where we don’t have overhead power.
Additional efforts to reduce emissions have been made with an installation of liquid recovery units. As we see every year in North Dakota, winter arrived in the fourth quarter. While we have seen the usual cold spells, we have not seen the typical amount of snowfall, which is worth noting because it should help all of operators avoid major slowdowns from their annual spring month season.
I’m pleased to say that our drilling operations continued to operate smoothly as we move through and beyond the horror winter in North Dakota. As completion operations take place, we have been exposed to the elements. We are seeing some of the normal delays that we begin to expect during the winter months. Operation of the workover rigs to perform routine maintenance is always more of a struggle during the cold winter months.
Thank you, Russ. At this time, it would be a good time to say thanks to all of our employees in North Dakota. They continue to drive home shareholder value and they are working some pretty challenging conditions at times. So, thanks to the entire staff up there.
Now, shifting gears and heading to our financial limitation, I’m going to introduce Aaron Gaydosik, our Vice President of Finance.
Thanks, Lynn and good morning, everyone. I will start by giving you a quick overview of our current operations in which we expect to spend approximately $940 million during 2014.
As we embark on our 2014 development plans, it is imperative to have a proper financing strategy in place to fund our CapEx program. One key piece to protecting our CapEx plan is our active hedging program.
Kodiak has approximately 26,000 barrels per day, hedged in 2014 at an average WTI price of around $93 per barrel. We are right on hedges for 2015, and expect to layer on additional volumes as we see the back month of the curve improve over time.
We have seen some positive movement in that regard as current month oil prices remained very strong. The operating cash flows which these hedges provide -- help protect, combined to a lesser extent with our revolver availability, provide more than ample funding for our 2014 CapEx program.
Our liquidity remains strong with $650 million currently available under our revolving credit facility. As always, we appreciate the efforts of our banks, which have been vital to the growth of Kodiak.
With 2014, EBITDA expected to be in proximity to 2014 CapEx, the $650 million of revolver availability should provide more than ample dry powder. As our production continues to ramp up during the year, we expect our borrowing base will also increase over time, allowing our liquidity to remain at healthy levels.
In order to maintain a balanced financing approach, we also continue to monitor the high yield debt markets, should it be advantageous to term out the portion of our short-term debt. Based on our existing rig count and the current commodity price environment, we expect our production ramp combined with our improved capital efficiencies to result in our debt to EBITDA on a run rate basis to be under 2.5 times as we exit 2014.
Our ability to meaningfully grow our production while also reducing our debt to EBITDA speaks highly about the quality of the rock and the hard work of the entire Kodiak team. In summary, we remain focused on maintaining a strong balance sheet while also continuing to improve our credit metrics over time.
Thanks, Aaron. We are going to follow that discussion with some color from Jimmy Anderson, Kodiak’s Chief Financial Officer on our reserves and drilling inventory.
Thanks, Lynn and good morning everybody and thanks for joining us. A couple of weeks ago, we announced our year end 2013 proved reserves as prepared by our third-party engineers, Netherland Swell.
As a reminder, our total proved reserves increased by 77% to 167 million barrels of oil equivalent from the end of 2012 and now calculates to a pre-tax value of approximately $3.5 billion using a 10% discount factor.
That’s a long way from the $4.5 million barrel of oil equivalents we had at the beginning of 2010. Since then, we’ve demonstrated nearly a 150% growth compounded annually. As for the make up of the proved reserves, about 46% of reserves are developed and 54% are undeveloped as of the end of the year.
Our methodology for booking these undeveloped locations involve bringing out our operated drilling schedule and then, adding in a non-operative locations for wells that have been proposed or committed.
In the end, this totaled about 400 gross locations, of which about 270 are operated, which equates to about 2.5 years of drilling at a current pace. Although, we believe our acreage is largely derisked, and we could book far more locations up to the five-year horizon, allowed under SEC rules, we chose to limit our PUDs to match our current plan and not get too far ahead of ourselves.
In the same vein, as we get more history on our infill wells, we think we should see improved per well reserves for those wells. As we’ve mentioned earlier on, and we haven't seen much change in production down-space test, so we believe that we will get some upside to these wells as compared to the current bookings.
In 2013, we’ve continued to complete wells in the Three Forks formation across our acreage and the Three Forks locations make up about 40% of our total operated wells in our reserve report. While these wells have great economics they are about 15% below the Middle Bakken wells on average as we have consistently discussed.
Looking forward we plan to continue to drill an equal number of Bakken and Three Forks wells each year. I should also mention that our year end reserves are about 83% crude oil and 17% natural gas. Obviously the Bakken is an oil play, over 9% of the economics are from oil. But as Bruce mentioned, we have continued to improve our gas sales which has added to the overall profitability of the play.
I would remind everyone that the associated gas produced is very rich and generally 1600 or higher btu. As we’ve increased our development of the west side of the play, this has become even more important as the gas oil ratio is much higher on that side. This higher GOR has reflected in our reserves as you can see the gas percentage has increased over last year.
As compared to our total estimated inventory using a conservative spacing assumption of around 10 wells per DSU, our proved reserves represent about a third of our total potential future drilling locations. As Ron discussed, we’ve done a lot of work this past year with down spacing and we expect the resulting density assumptions will increase as we get more comfortable with that data. Clearly we have more years of drilling ahead of us and we believe that we will continue to see consistent reserves growth well into the foreseeable future. Thanks.
Thank you, Jim. I think Jim, he was the happiest about this new format as he didn’t have to repeat all the numbers we just put in the 10-K but we appreciate that.
Lastly, I am going to turn over to Mike Murray, our Vice President of Land to quickly share his opinion on continued acquisitions and divestitures in the basin. Mike?
Good morning everyone. We just recently closed on a transaction where Kodiak divested of about 19,500 net acres and about 300 BOE per day, for just over $68 million. All of these properties were located in Southwestern McKenzie County. To date we've not seen production results on par in those properties in comparison to our core properties. This sale was a continuation of our effort to high-grade properties that Kodiak has been working on diligently over the past couple of years.
After this divestiture to several other minor trades and acquisitions, Kodiak’s current acreage position stands at approximately 361,000 gross, 183,000 net, with our net Williston basin holdings making up roughly 327,000 of the gross and 173,000 of the net. At this time, less than 10% of our acreage located principally on edges of the play is not held by production.
As this play continues to be developed, the opportunity to significantly increase our acreage position presents many challenges. However we will continue to evaluate all opportunities to increase our operated position via trades and acquisitions. While there are inherent issues that accompany oilfield operations, we continue to go out of our way to build relationships with the landowners and respective governing agencies. We feel very fortunate to work with the good people of North Dakota. From the top down, we hear Kodiak appreciate our operations and how they impact the lives and lands of the people living in and around our operations. And our guys do their best to allay that sentiment and show that we are intent on being good neighbors.
Thank you, Mike and thanks to everybody this morning here for sharing your thoughts. I hope all of our listeners have enjoyed hearing some unfamiliar voices this morning, an opportunity for them to share the thoughts and enthusiasm what we are up to here at Kodiak. I hopefully have touched on areas of interest and that you found this format more enjoyable than just a discussion on numbers. The voices you just heard are the voices of our management team that work with our incredible staff, so that all of us can share in the growth that Kodiak has experienced and will continue to be a part of the wonderful ongoing opportunity. We expect to spend about $940 million in 2014 to drill about 100 net wells. Our continued gains in drilling and completion efficiencies, coupled with lower drilling and completion costs, should allow us to have confidence in this achievement.
With that, we want to thank our listeners for joining us this morning. We will turn it back to the operator for Q&A session. Thanks.
(Operator Instructions) And the first question comes from Ryan Oatman with SunTrust.
Ryan Oatman - SunTrust
Hi, good morning.
Ryan, how are you doing?
Ryan Oatman - SunTrust
Doing well. May be a question for you, Russ, here, but another company and the play was talking about completion activity across the basin, really slowing this year. Can you speak to that and kind of your comfort around the previously disclosed 36,000 to 38,000 barrel a day guidance for the first quarter?
Ryan, I’m not sure which company you’re referring to. I think here what we’re doing is pretty much on pace to what we’ve laid out. We’re through February here. It’s been a little bit slow. There is no doubt about that. I think we’ve got some big pads that we’re brining on right now, try to commend production in March. I think it’s going to be a typical ramp-up that we’ve seen last couple of years. I think second and third quarters are big quarters, and the first has always been slow. And I think as we get in to fourth quarter, it starts to slow down. So I am not sure what you’re referring to, but I thought pretty confident where we’re at, I like our numbers.
Ryan Oatman - SunTrust
Okay, it’s very helpful. And then looking at lease operating expense, it does sound like there is lots of potential improvement in that regard. With these new unit boss rigs, can you talk about the benefits of using gas versus diesel and kind of how that could help kind of not only the operating expense side but also on the gas flowing side potentially as well?
Yeah, Russ, I am going to let you describe a little bit what we’re thinking about that.
The new rigs will be dual fuel so it will run more natural gas which of course will lower your fuel cost. What we plan for diesel out there, and you have the same horsepower, they are all 1,500 horse rigs that, they will be just as efficient as running rigging boiler on natural gas. I think it will be great upgrade for our current rig situation.
Ryan Oatman - SunTrust
Can you use the field gas on it or is it too high?
We’ve got a strip, but then we should be able to use it.
Ryan Oatman - SunTrust
Okay. And then shifting over to this Polar 2.0, was one that separate the formats of this Bakken and Three Forks wells. On the Bakken wells, can you describe how those are looking relative to your expectation early days? And then I’ve got couple quick follow-ups on Three Forks.
Yeah, I think from a Middle Bakken standpoint, I think these wells look almost nearly identical to the six others that we brought on just to the west here early last year. I think Three Forks, again we see more variability in the Three Forks. These wells are still good. I do want to repeat, I mean we brought these on in late December and January, and so all the production had been a little bit more of a challenge. So, again, I would just tell you, let’s not read too much into early numbers, I think these are really solid wells. I think our staff is very pleased when we stimulated. We didn’t see a lot of communication between wellbores, I think that’s what exciting for us. So give us some time on this, I think they look pretty strong Ryan.
Ryan Oatman - SunTrust
Okay. In the Three Forks wells, were those both upper or was one an upper and middle?
We actually tried to drill this and kind of the markers that lies between the upper and middle interval. Of course, they are not a straight line, they would go around a little bit, but they are pretty much drilled in the same type available.
Ryan Oatman - SunTrust
Got you. That’s right. How applicable do you think what you find here on this Polar 1.0, 2.0, how applicable across your acreage do you feel like that will be whatever spacing it ends being? And with that, I will hop in the queue. Thanks.
It’s probably going to vary as we move around our different blocks of acreage, obviously this whole Polar, Koala and Smokey areas are pretty good, this is whole Polar, Quala [ph], Smokey areas are pretty critical part of our operations. We are doing a lot of work over in Dunn county, obviously that’s some of the best work we have. So we have tried to kind of clean up the portfolio as Mike discussed and think what we’ve got left is a pretty much first class type property that I think you're going to see quite a bit of infill drilling here. And what the ultimate number is I don’t think we know yet, as I don't think other operators. So we’re going to continue to work towards this and I think we’re pretty pleased at the end of the day.
And our next question comes from Hsulin Peng wit Robert W. Baird.
Hsulin Peng - Robert W. Baird
I guess a follow up question to the spacing, so the 100 net wells program in 2014, other than Polar 2.0 and Dunn county well that you talked about, can you tell us what the average spacing of this or – that you plan?
Good morning, Hsulin. Yeah I don’t know if the average is proper but we are putting most of our wells kind of within the same formation, we’re kind running anywhere from probably 550 to 700 on average. I think when we look at the Three Forks again, we’ve got some more work, we want to get some more production to see how we are going to develop the Three Forks. We’ve laid out that we are going to test maybe lower zone a little bit, we are still doing some work, we are trying to evaluate the numbers. But again we are drilling wells – the Three Forks, generally by that same kind of 600 to 700 type number. So I think that’s probably a decent number to work with. And we are kind of doing that across that board right now. We’ve moved from that standpoint probably early first quarter, late fourth quarter probably.
Hsulin Peng - Robert W. Baird
And then second question is in terms of the cost structure improvement and the infrastructure and also efficiency gains, I was trying to find out if you have a target percentage or absolute number for LOE in terms of pace and cost in 2014?
I think we kind of guided to that 650 number more or less, Jimmy, do you have some thoughts?
I think the guys have done a great job keeping our costs in control, you saw in fourth quarter we are right around 650 I think per boe on a corporate basis, and it’s quite the cold weather and tough working conditions, the guys have done a great job. And as Russ spoke to quite a bit on water side and really early days for some of these initiatives on the gas generation that we should see continued savings. I think that those savings will offset some of the increased costs in different areas, mostly kind of maintenance type items as are wells [indiscernible] and we see a little more work being done in the field. I think we are kind of guiding towards holding steady about that rate and hopefully Russ and guys can deliver better results.
Now on the transportation gathering, I think that's largely a function of how much gas we sell as percentage of the total and as we get more and more oil on pipe as Bruce spoke to, we've made a lot of progress on both, it’s just kind of a switch from our netback price for selling by truck to moving it over to the pipelines and giving a slightly better netback but I think overall you will probably see it remain in the same range that we have been running for the last few quarters right around 2 to 220 per boe.
Hsulin Peng - Robert W. Baird
And then I know you are still waiting for more production from the down spacing pilots but I was wondering if you kind of help us with the – in terms of the timing and updated inventory, how much more production history do you need?
Let us move through the year. I mean we’re excited about what we are seeing. I think the first down spacing projects, I mean I think we are close to 180 days, and the wells look good. We’re really excited about it. I mean everybody wants to hear now. I mean let’s move through the year and we get more data. I think the last four wells, obviously it’s early, and we are going to be cautious but I think we said this before, as we have trailed around, we haven’t seen anything that’s making us nervous at this point which is a real positive. So hang with us. We’ll continue to put this out. We tried to be pretty transparent when we’re thrown out there. And we’ll continue to show you as we move along.
Hsulin Peng - Robert W. Baird
Okay. And then the last question and I’ll move back in the queue. Just a clarification, the current 1Q production guidance, is that net of the recent divesture?
Yeah. That wasn’t much. We had only 300 barrels related to that. We think we’ll make it up.
Hsulin Peng - Robert W. Baird
Okay. Perfect. Thank you.
Thank you. Next question comes from Welles Fitzpatrick with Johnson Rice.
Welles Fitzpatrick - Johnson Rice
Good morning. It looks like the top end of the EUR curve and Wildrose came down a little bit. And I know you guys thought of the idea in the past but do you think that could be on the slate as a divesture candidate in ‘14?
Well, I think we’ve been pretty clear. We look at that kind of a tier 2 type property. So we just completed a series of wells. I think five wells are there in the first quarter here. That’s why some of our production ramp isn’t as large as you will see within the year. I don’t think we’ve got new surprises. This is not core area. We want our HBP to acreage. If we decide to hold it, we can -- we don’t have to draw in the near term and come back to it later dates.
So let’s see where we shake out. We’re trying to get the wells all on pump here. We’ll go through the rest of the quarter and in the second quarter and then we will see where we go. So give us a bit and see what happen.
Welles Fitzpatrick - Johnson Rice
Great. That’s perfect. And then just one more on the LOE 650 and it maybe that they kind of ramping down to the year as disposal efforts go on or should we keep that sort of flat for the year?
I think, we probably encourage you to keep them flat. I mean, we hope to see some improvements wells but I think we need to get down the road a little bit because we continue to work over such as nature of the beast here. So I think we’ll probably use that number going forward as a reasonable approach.
Welles Fitzpatrick - Johnson Rice
Great. That’s perfect. Thanks so much.
Thank you. The next question comes from Gail Nicholson with KLR Group.
Gail Nicholson - KLR Group
Good morning everyone. Just two quick questions, you got a really good job increasing your backfill volumes year-over-year. I know there is some compression issue s and capacity on the gas infrastructure side in the basin. How should we approach on the gas volumes here as you guys move throughout ’14, and get to the end of ’14? Are you guys thinking of another increase or what’s about there?
Yeah. Gail, we just returned compressing with lot of our -- one of our gas purchasers. We’re trying to layout our drilling program, really for the next three years and show more volume are going to come from. We hope this will help us improve. We believe we’ll make some progress. We are seeing some changes here in the first quarter as Bruce described. Unfortunately, there’s still lot of wells to be completed and the gas pipeline is filling up pretty quickly and the pressure is build up. So, it’s a little bit of chasing your tail here but I think the basin overall is making progress. Russ, do have any initial thoughts on that that you would like to share?
I think, definitely there is progress being made. Also I should mention that there is a task force that’s been formed and doing good work, trying to hit some goals of increasing the flaring and then also maybe recovering some of the liquids from the wells that aren’t flared. So you could get some revenue stream from those. So things are moving forward.
Gail Nicholson - KLR Group
Okay. Great. And then just regarding the netback pricing, when you guys sell directly to the refiner, are you getting a better netback pricing on that of those volumes sold? And then, looking at the volumes that do get railed to the east coast, is that based on the Brent pricing less transportation or how is that being calculated?
We do, we have a contract that is actually based on Brent and then we have contracts that are based on [Calderon] and NYMEX like the rest of our contracts in the basin. But it is a Brent price basically. So we did see in January, February, some pretty good differentials there, that was our best contracts for those months. But I think, probably for March, for a month or two, we could see that move back in line with maybe a clear growth number.
Gail Nicholson - KLR Group
Okay. Great. Thank you very much.
Thank you, Gail.
Thank you. And at this time, I would like to turn the call back over to management for any closing comments.
All right. Thank you. At this time, I want to applaud our staff. Everybody here in Denver and North Dakota, everybody’s working together. I think we’ve done a great job moving this thing forward. So, a huge thank you to everyone.
Yeah, the Williston Basin continues to gather. We believe the work being done on downspacing will continue to drive this thing hope. They will continue to say, it’s a great time to be a player in the Williston. We continue to see robust oil prices along with improvement differentials, we are seeing a well cost come down, we are seeing these downspacing projects work and all these are yielding some pretty improving economic returns.
Before we signoff this morning, I would to take a moment to remember a friend and colleague, Mitch Wurschmidt, who tragically left us early this week. I met Mitch about 15 years ago when he was on the sale side. Mitch was always a big supporter of Kodiak but more important he became a good friend over the years.
As he moved to the buyside last couple years, we saw and shared some time with his various conferences. I thought some prayers go after his wife and young children, as well as all his colleague that are sharing same pain. I ask all of our listeners and shareholders to maybe give a friend, a coworker, a loved one or even a stranger, hug, you never know the stress that someone might be going through and just what hug might mean. So it’s been a tough week for lot of us and we certainly are here for the family.
I’d like to thank everybody for listening this morning. I hope you enjoyed the format. I hope you got some good Intel into the basin. We will be seeing some of you next week as we travel throughout New York and Boston, and then probably a whole bunch of you as we go to The Big Easy at the end of March. So thank you very much and have a great weekend.
Thank you. The conference is now concluded. Thank you attending today’s presentation. You may now disconnect. Have a nice day.
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