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Unit Corporation (NYSE:UNT)

Q4 2013 Earnings Conference Call

February 25, 2014 11:00 AM ET

Executives

Larry Pinkston - President and CEO

David Merrill - SVP, CFO and Treasurer

Brad Guidry - EVP, Exploration of Unit Petroleum Company

John Cromling - EVP, Drilling of Unit Drilling Company

Bob Parks - Manager and President of Superior Pipeline Company, L.L.C.

Analysts

Marshall Adkins - Raymond James

David Amoss - Howard Weil

Marc Bianchi - Cowen

Blake Hancock - Howard Weil

Operator

Welcome to the Unit Corporation Fourth Quarter 2013 Earnings Conference Call. My name is Richard and I’ll be your operator for today’s call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.

During the course of the conference call today, the speakers may make statements that constitute projections, expectations, beliefs or similar forward-looking statements. The company’s actual results could differ materially from the results anticipated or projected in any such forward-looking statements.

Additional detailed information concerning the important factors that could cause actual results to differ materially from the information given today is readily available in today’s press release under the heading forward-looking statements. This document is available on the company’s website.

I will now turn the call over to Larry Pinkston, President and CEO. Mr. Pinkston, you may begin.

Larry Pinkston

Thank you, Richard. Good morning everyone. We want to thank you for joining us this morning. With me today are David Merrill, Brad Guidry, John Cromling and Bob Parks. Each of these gentlemen will be providing you with updates concerning their segments. We will then take questions after the conclusion of their comments.

We released fourth quarter and year end 2013 results this morning. Net income for the quarter was $51.3 million, or $1.05 per diluted share. Adjusted net income, which excludes the effect of the non-cash commodity derivatives, was $54.3 million or $1.11 per diluted share. Total revenues for the quarter were $359.1 million which is 49% oil and natural gas 28% contract drilling and 23% midstream. Our non-GAAP financial measures reconciliation is contained in our press release.

Net income for 2013 was $184.7 million or $3.80 per diluted share. Adjusted net income for 2013, which excludes the effect of the non-cash commodity derivatives, was $188.8 million or $3.89 per diluted share. Total revenues for 2013 were $1.4 billion, which consisted of 48% oil and natural gas, 31% contract drilling, and 21% mid-stream.

For oil and natural gas segment total production during the fourth he quarter was 4.4 million barrels of oil equivalents, an increase of 5% over the third quarter of 2013 and an 8% increase over the fourth quarter of 2012. Total liquids is both oil and natural gas liquids production increased 21% over the comparable quarter of 2012. Total production for 2013 was at the top end of our production guidance or an 18% increase over 2012.

The value of our estimated year-end 2013 proved reserves was $1.8 billion, an increase of 21% over 2012. Our estimated year end 2013 proved oil and natural gas reserves were 160 million barrels of oil equivalents or 960 million cubic feet of natural gas equivalents as compared with 150 million barrels of oil equivalents or 899 bcf at year end 2012, which was a 7% increase. We replaced approximately 161% of our 2013 production. Estimated reserves were 13% oil, 26% natural gas liquids, and 61% natural gas. During 2013, we also divested 3.5 million barrels of oil equivalent of non-core oil and natural gas reserves.

Moving to the contract drilling industry, the market of the fourth quarter continues to be soft in the fourth quarter, with our fleet utilization increasing 2% over the third quarter. We have seen an increase on the utilization since year-end 2013 with feasibility for continued improvement through the first quarter. During 2013, we sold four 2,000 horsepower drilling rigs, and one 3,000 horsepower drilling rig to an international buyer. Subsequent to the end of 2013, we sold four additional 3,000 horsepower rigs, bringing our total fleet to 117 rigs. The proceeds from these sales were use in our new BOSS drilling rig program.

Our first BOSS rig will be commissioned tomorrow at our Oklahoma City Yard prior to being placed in the service with our oil and natural gas segment. We are excited about the level of interest in the BOSS rig and we’re seeing some operators prior to the first rig even being placed into service. John Cromling will provide some additional detail momentarily.

Our midstream segment, liquids sold value per day increased 49% over the fourth quarter of 2012 and we’re essentially unchanged year-over-year. Gas gathered volumes per day increased 12% and 24% over the fourth quarter of 2012 and year-over-year respectively. Operating profit was $43.9 million, an increase of 46% over 2012. Looking forward, we’ll continue to see progress on many of our key initiatives in each of our business segments, and anticipate a very strong 2014.

At this time, I’d like to turn the call over to Brad Guidry to discuss our oil and natural gas segment.

Brad Guidry

Good morning. Overall Unit has two areas of operations for C&P program, the Mid-Continent region and the Upper Texas Gulf Coast. Within the Mid-Continent area, we’re primarily focusing on four horizontal oil and liquids rich gas resource plays, including the Granite Wash, the Marmaton, the Mississippi and new Emerging play. Unit has a total of 330,000 net acres of these four core plays. In the Gulf Coast region, we are mainly focused on the Wilcox which is a conventional liquids rich gas play with significant potential. The Wilcox has so far been drilled vertically but it appears it also have a promising horizontal application. The consistency provided by our resource plays coupled with the upside potential from our conventional play provides a balanced well inventory for future growth. 2013 was a good year for the EP segment. We increased annual production by 18%. We increased our reserves by 7%. We reduced our overall finding cost by 18% and finally we accomplished these goals while spending approximately 9% less than what our 2013 capital budget was.

The success in 2013 is mainly a reflection of the quality of our core plays and our strategy to focus on those core plays. For 2013, we averaged 9.7 unit rigs working in our core plays and then we anticipate run it in average of 12 unit rigs in 2014 which is approximately 25% projected increase. Currently, we are running 11 unit rigs; three are in the Granite Wash, two in the Marmaton, two in the Mississippian, two in the Wilcox, 1 in the Emerging Play and one in the Cleveland. Unit’s new BOSS rig is scheduled to start drilling in our Granite Wash play in March 2014. We have experienced some weather related production losses and operational delays this winter that will primarily impact our first and second quarter 2014 results. At this time we are not adjusting our 2014 production guidance of 15% to 18% growth, however we will monitor this closely as we foresee through the second quarter.

Now let’s take a brief look at the operational updates for the core plays. Starting out with the Wilcox located in Southeast Texas; we are excited about the future potential of this play. Unit achieved its fourth consecutive quarter of production growth with production increasing 12% during the fourth quarter ‘13 compared to the third quarter of ‘13. Annually, 2013 production was up 21% over 2012. The strong quarterly annual production growth is mainly attributable to new well completions primarily in the Gilly, Basal Wilcox field. At the end of 2013, there were eight vertical wells and one horizontal well produced in Gilly Field. Two noteworthy wells were recently drilled to test the eastern and the western limits of Gilly Field. The eastern well was encouraging based on encountering approximately 192 feet of potential pay suggesting the possible extension of the field further to the east. However, the western well encountered tight sands resulting and temporarily abandoning the well.

The resource potential for the Gilly Field is still in line with our previous estimate of approximately 220 Bcfe net of which 38% is booked as proved reserves at the year-end 2013. Our first horizontal Wilcox well was completed in November of 2013 with approximately 1,500 feet of lateral from the base of Wilcox sand and the Gilly Field. This horizontal location was chosen because it allowed us to drill in case of the main producing sand intervals in Gilly Field prior to going horizontal on the deeper and tighter lower Wilcox zone. The incremental cost to drill the lateral portion of this hole was approximately $3 million which is significantly less than drilling a new well. The initial rate of approximately 4.8 million cubic equivalent feet of gas per day was in line with expectations considering the short lateral wells and the lower quality of the targeted Wilcox sand.

We need more production data to adequately estimate the ultimate recovery and economics of the horizontal portion of this well. However, we are encouraged that horizontal drilling currently appears to be a viable application in the Wilcox play. To east in Newton County, we drilled two vertical Wilcox wells that have several potential oil and gas sums based on the walls. Both of these wells refract last week and are currently flowing back. Let’s move to the mid-continent area, in the Granite Wash play located in the Texas Panhandle, we have completed drilling operations on our initial nine well programs in the main part of Buffalo Wallow field. The nine wells are located on three different pads and there are three wells per pad that will target five different Granite Wash wells including the F1, the E, the D, the C1 and the B sands. Two of the pads have been fracked and the third pad is scheduled to be fracked in mid-March. The current plan is to monitor production for approximately 90 days at which time we will discuss the results for all nine wells and plan to resume pad drilling in the field.

For 2013, we completed 23 Granite Wash wells with an average 30 day IP rate of approximately 5.2 million per day which is approximately 25% higher than what our 2012 average was but it’s in line with our historical Granite Wash rates. Production for the year was up approximately 28% over 2012. We are currently running three rigs in the Granite Wash and anticipate Unit’s new BOSS rig to begin drilling in March on a three well pad location southeast of the Buffalo Wallow field. At our Mississippian play located in south central Kansas, we are currently running two rigs and continuing our program to evaluate our leasehold. For 2013, we have first sales on eight Mississippian wells with an average 30 day IP rate, 222 barrels oil equivalent per day, consisting of 53% oil, 11% NGLs, 36% natural gas. However, the last four wells that we completed in the fourth quarter of 2013 had significantly higher oil at 79% oil, 6% NGLs and 15% natural gas. It also had a slightly higher IP 30 day rate of 231 barrels of oil equivalent per day.

These four wells are located in the same general area and appear to have similar production characteristics. The current plan is to focus our drilling program in this general area as we test different frac designs as well as the potential for extended lateral wells.

Moving to the Marmaton oil play located at Beaver County, we completed 41 horizontal wells during 2013; the average 30 day IP rate was 371 barrels of oil per day at an average working interest of approximately 75%. Today all of Unit’s wells have been completed in the upper part of the Marmaton. However we recently completed our first well from the lower section in the Marmaton. The well is only being online for approximately two weeks but we’re encouraged with the early results and plan to drill several additional wells targeting the lower Marmaton interval. In addition, we’re planning to test the shallow Kansas City Lancing interval in existing vertical well on the next 30 to 60 days. If this test is positive then we will schedule to drill horizontal well in the zone.

Unit announced a new emerging play at our Analyst Day in December 2013 that is located in the Oklahoma portion of Anadarko Basin. We’re continuing to build our lease hold position in the play and currently have approximately 25,000 net acres with approximately 11,000 net acres that are located in the area we consider the current core. And another 14,000 acres located in the potential expanded play area. We currently have one unit rig drilling and anticipate adding a second rig in late second quarter.

In summary, we’re pleased with both the fourth quarter and the overall 2013 results. We have complied the balanced portfolio of desirable core properties that positions unit for future growth. At this time I will turn the call over to John for the drilling company update.

John Cromling

Thank you Brad and good morning. Our contract drilling segment has shown improvements in several areas during the fourth quarter despite operating in a relatively flat rig market. Day rates decreased slightly during the fourth quarter, the average day rates for the fourth quarter was 19,630 as compared to 19,773 for the third quarter. However, the average total daily revenue before intercompany eliminations decreased by only $90 per day during the fourth quarter, primarily, due to the increase in mobilization revenue and other revenue. Total daily operating cost before intercompany eliminations decreased $303 per day for the fourth quarter as compared to the third. The average per day operating margin for the fourth quarter before the elimination of intercompany profits was $8,132 which is a $212 per day increase from the third quarter.

Our average rig utilization during the fourth quarter was 65 rigs, which is a 2% increase over the average for the third quarter. Rig utilization has been increasing since year-end, we’re currently operating 69 rigs and should exit the quarter with 72 rigs to 73 rigs operating.

Last year, we initiated a comprehensive evaluation of our drilling fleet. Part of that evaluation included a review regarding the need to realign our fleet’s capabilities and efficiencies in view of the current demand for drilling rigs, using new technologies and capabilities. As part of our evaluation we determine that we should pursue to sell several of our older and larger drilling rigs that have not worked for some time.

We completed the sale of an idle 2000 horsepower rig and an idle 3000 horsepower rig during the fourth quarter, bringing a total number of rigs sold during 2013 to five. All of these rigs were sold to 200 affiliated contractors which will operate the rigs in Mexico. In addition to those five rigs we completed the sale of four additional idle 3000 horsepower rigs after yearend.

Proceeds from the sale of these rigs will be reinvested in the construction of our new 1500 horsepower AC rigs. Our BOSS rig will be the prototype for the future expansion of our rig fleet. The rig will incorporate features to move more efficiently and also to walk on multi-well pads. There are many other components of the rig that were permitted to excel at horizontal drilling, especially in the drilling fleet system.

Our first BOSS rig is being placed into service next week; two additional BOSS rigs are contracted to an operator in North Dakota and are scheduled to go into service during the second and third quarter of 2014. We also are very close to signing the contract for another BOSS rig for the third quarter. We will continue to refurbish rigs as the market dictates and we expect much of this growth will happen in the 750 to 1000 horsepower range in the Mississippian play, but certainly not restricted to this area. Several of the 1,500 horsepower rigs operating in the Bakken has been upgraded with pumps in that systems, which will allow them to operate in the 7,500 PSI range. This is a feature that oils operators to improve their efficiencies in the very long laterals that are now being drilled in North Dakota.

As the demand for 1,500 horsepower rigs equip for horizontal drilling has increased in the Permian area, we have been able to establish our presence there. Presently, we have three rigs operating in the area and three more rigs contracted to be moving into this area within the next couple of months. The combination of our inventory of rigs, people and a strong financial base will allow Unit to continue to expand with the market.

I’ll now turn the call over to Bob Parks.

Bob Parks

Thank you, John. The midstream segment completed a successful year and set records in several key areas. Activities in our core areas are increasing and we continue to produce both strong financial and operational results. Midstream segment finished the year with record results mainly due to an increase in gas process and liquids sold.

Operating profit for the fourth quarter of 2013 compared to fourth quarter of 2012 increased 89%. Our process volumes per day for 2013 were up 5% compared to 2012 to an average of 140,584 Mcf per day. Process volumes per day increased primarily from new wells throughout 2013 along with the addition of new systems and expansion of existing systems.

Our natural gas liquids gallon sold per day increased 49% in the fourth quarter 2013 compared to the fourth quarter of 2012, up to an average of 656,415 gallons per day. This increase is primarily due to higher volumes at our Bellmon [indiscernible] and Perkins (Ph) facilities due to connection of new wells and improving our processing facilities.

During the first part of 2014 with the increase in liquids prices, particularly propane, we are now operating in full recovery mode in all of our processing facilities. During 2013, we invested $96.1 million in capital projects. The majority of the capital expenditure or for completing the Pittsburgh Mills gathering system, constructing our new Reno facility and expanding our existing Bellmon systems. For 2014, our estimated capital expenditures excluding acquisitions are $78 million.

I will now discuss areas of significant activity for the midstream segment. In the Mississippian play, we continue to be very active and it remains a key area of focus for our midstream segment. Our Bellmon facility located in North Central Oklahoma currently consists of approximately 185 miles of pipeline and includes a 20 mile NGL line, two processing plant skids and the ready compressor stations.

In the first quarter of 2013, we completed the installation of a new 30 million cubic feet cryogenic processing plant, which allowed us to take out of service our original rental processing plant. Due to increasing volumes at this facility, we also completed the installation of an additional 60 million cubic feet processing plant skid which will be operational in the first quarter of 2014. With the addition of this new plant and the termination of the Reno plant contract, our processing capacity at this facility will be approximately 90 million cubic feet per day.

Also in the Mississippian play, we’re completing construction of a new gathering system and processing facility at Reno County, Kansas. This facility consists of approximately 20 miles of gathering pipeline and two processing plant skids, 5 million cubic feet per day refrigerated JT skid and 20 million cubic feet per day to standard (Ph) skid. Both of these plant skids are operational and it provide us with approximately 25 million cubic feet per day of processing capacity. We began gathering gas at these facilities in the second quarter of 2013 and began processing gas in the third quarter of 2013.

In the Appalachian area, our Pittsburgh Mills gathering system located in Allegheny County, Pennsylvania consists of 14 miles of gathering pipeline and a compressor station at the completion of the first phase of this project. We have 19 wells currently connected to the system with plans to continue to add wells as they’re drilled and completed. Phase two of this project will extend our pipeline north into Butler County, Pennsylvania. We’ve acquired it write-away and are proceeding with environmental and regulatory requirements. Construction of the second phase of this project is expected to take place in 2014.

In summary, we’re continuing to focus on our core business areas, completing several expansion projects on existing systems, adding additional processing capacity and undertaking new development projects. These efforts continue to increase our presence in these core areas. Additionally, we’re continually exploring new areas in which to expand our midstream business. The combination of these activities position us well for future success as we continue to expand and grow our midstream business.

I’ll now turn the call over to David Merrill.

David Merrill

Thanks Bob. We ended 2013 with total long term debt of approximately $646 million which was all finger subordinated nouns (Ph) with no borrowings under our credit facility, giving us the conservative debt-to-capitalization ratio of 23%. Our current borrowing base associated with the credit facility is $800 million. We have elected an available commitment amount of $500 million, all of which is available at the end of the fourth quarter and we have the full $800 million of availability associated with our borrowing base.

For the oil and natural gas segment, operating cost in the fourth quarter decreased 9% from the third quarter. A portion of the decrease is attributable to lower work over activity and production tax credits refunds associated with high cost gas well. The effective income tax rate for 2013 was 38.7%, and we currently estimate the rate for 2014 to be approximately the same. The current portion of income taxes for 2014 is estimated to be approximately 30%. For 2014, our operating segment capital expenditures budget is 928 million or 34% increase over 2013; our budget in capital expenditure by segment of $718 million for the Oil and Natural Gas segment, $132 million for the Contract Drilling segment and $78 million for the midstream segment. The 2014 capital program as anticipated to be funded using internally generated cash flow proceeds from non-core assets sale and credit facility borrowings if necessary.

And Richard we would now like to turn the call over to you for questions.

Question-and-Answer Session

Operator

We will now begin the question and answer session. (Operator Instructions) Our first question on the line comes from Marshall Adkins from Raymond James. Please go ahead.

Marshall Adkins - Raymond James

Got a couple of few questions, we’ll start on land drilling side. Are you starting to see reactivation of the SCR rigs? It seems like we are seeing pretty solid cash flow from the industry and elsewhere reactivation of the electric rigs, so you’re seeing that? Or is it more in the smaller end stuff in the Mississippian?

Larry Pinkston

Marshall we are seeing a greater increase in last two or three weeks in the 1500 SCR rigs. In fact by the end of next month all of those type rigs in the Mid-Continent and Gulf Coast will be active and we will only have three or four in the Rocky Mountains there are not active at that point. Yes, it has been a good increase for us.

Marshall Adkins - Raymond James

I know maybe it’s a little bit early but it sounds like you got the first BOSS rig running this quarter. How is that running so far, is it too early to go?

Larry Pinkston

Actually we are having our rig show tomorrow. We have gone through all kinds of testing with it of course. We have the rig show tomorrow and in early next week will rig it down and move into the first pad.

Marshall Adkins - Raymond James

And the last thing on that, from the commentaries it sounds like you are looking to build more of those, any update on how many you think you might build?

Larry Pinkston

We have plans right now and commitments for the next three.

Marshall Adkins - Raymond James

Okay, that’s it.

Larry Pinkston

Marshall, we would like to get 5 to 6 of them in the field this year and you know we are pretty confident that we have the ones contracted, that we don’t for the five to six, and that will kind of depend on whether we can get them completed by the end of year. But our goal is to get them kind of spread out across different operating areas, as of marketing rig in each of the areas and we're certainly hopeful that we'll build many more in ’15, that we will wait on those for a contract before we build them.

Marshall Adkins - Raymond James

Sounds good, it makes sense, all right. Switching to ENP, you drilled that first horizontal in the Wilcox, and it sound like you're still evaluating it. Can you give us a little more color on where you think the horizontal future lies in that play.

Larry Pinkston

Yes, the first horizontal we drilled was really just to test the idea mechanically could we drill the lateral? What kind of uptick we would have? And as I mentioned which was really picked because it minimized our capital exposure because we knew we have the shallow pace and the incremental cost weren’t that much. The application for horizontal and Wilcox I think we’ll have a number of different applications from these, nearly enhancing production at existing fields that had not been effectively produced. I think it has an application of looking at zones that were marginal or uneconomic in vertical wells and you know you remember we drilled over 100 wells in this play. We tested a lot of different sands. Like many of the horizontal plays, vertical wells are sub economic and you drill horizontal well may become economic. It will take some time to develop a base. It's not like, every sand we drilled out there and tested with some gas out, will be economic. But that’s really what we will be doing over this next year, is picking different targets. The other application we are looking at is we have some areas primarily more an oily areas that we’re looking at, that could’ve effectively produced in areas that were below essentially the known oil production. So in other words there is a transition zone below where vertical wells produced oil down to wells that have shales, and could horizontal drilling open that potential area up. So there is a number of different application, and then it will certainly be a process. It won’t replace or vertical drilling in any means but we do see it as an application that will supplement what we have been doing out there for the past 10 years.

Marshall Adkins - Raymond James

Okay, that’s great. Then the last one, update us on the trends and the IP rates over the Granite Wash and the Mississippian. What are you seeing there? Are things continuing eke higher on the IP rates or we kind of stabilized on that front?

Larry Pinkston

Yes, the Granite Wash the IP rates for ’13 were in more line what we had in 2012 was certainly a year we were below our average rates, we had some wells that brought that down that were more in the extensional type wells. So ’13 was the year we really got back into that level. I mean typically on Granite Wash wells if we’re somewhere in 5 million a day equivalent 30 days IP rate that’s historically where we want to be. The biggest change we will look at, we will see with the Buffalo Wallow wells look on IP rates we have there. What data we have in Buffalo Wallow didn’t necessarily indicate that we’ll have substantially higher IP rates it’s just that what we’ve seen form the existing production is there may be a little bit flatter declined than what we’ve seen. So those are all the combination that we’re looking at.

Our results for ’13 for Granite Wash have pretty much been in line with what we’ve expected. The Mississippian really the 30 day IP rates haven’t changed that much just what we’re trying to do is focused more in where we’re seeing more and where we part of the play is where we drill our rest initial well in the play where we have those history. So these last four wells we drilled and then there is a couple of wells we drilled subsequent to the fourth quarter that would also fit in that range that they seem to have same production characteristics so it’s more function if we try different frac design there, we’ll get pretty good test case since we think the rock and the oil mix in that area is pretty similar. So again, we really don’t have enough data to set up a trend even way. But certainly the higher oil cut in there, we’re pretty encouraged with.

Operator

Thank you. Our next question on line comes from Mr. David Amoss from Howard Weil. Please go ahead.

David Amoss - Howard Weil

Brad, could kind of go into little bit more of the weather impacts that you saw that bled into 2014? I mean you’ve noted a little bit of impact on first quarter and second quarter possibly. What areas are affected? How are they affected? And just kind of trying to a get feel for how production grows throughout the year. I know you kept the guidance in same range.

Brad Guidry

Most of it was in the economy. We did have some freight (Ph) loss that in the Gulf Coast region, but primarily it was Mid-Continent area. There are really two different things we’re looking at here with production losses. We’re looking at just peer loss of wells that we’re producing that were shutting or froze off and actually production that just was lost due to weather. And we have a preliminary estimate in January that somewhere around 340 million for the month of January that didn’t include February or anything beyond that of just that peer production loss.

The secondary part of that delays that were created by weathers so essentially we didn’t get as many fracs done as we expected. The drill curves that we had to be finished with wells and get that done, gets delayed pipeline, gets delayed operationally things just gets slowdown because of the weather. So that numbers are little bit harder to give actual number of the loss. At the end of the first quarter, we’ll certainly put a number on that to the best we can but it’s more a loss due to what we have projected from our guidance earlier.

David Amoss - Howard Weil

Okay, got it. And the in the Mississippian, the oil cuts to look much higher the most recent oil, can you kind of -- it doesn’t sound like you’ve got the entire acreage position delineated to your satisfaction but the way that you’re thinking today, can you generally give us what part of our acreage you think falls into that higher oil cut region versus what maybe a little bit gassier?

Brad Guidry

The general area we’re talking about now is about township size. So we really haven’t stepped further out from that. The original when we first started talking about Mississippi and we had drilled wells in three different areas and the results in those areas we had little bit varied mix oil and gas. And for us to really be efficient on the frac design, we needed to be in area where we felt that the overall rock characteristics were pretty similar. So we’ve kind of focused in township range and I’m not saying that it’s just one township that will be that but because we have much more acreage outside of that area that I think will be in the same characteristic as that. It’s just at this time because we’re trying to get the play over the hump essentially from the economics. We want to focus in that area where we know the rock is similar. That way when we do a different frac, we can feel pretty comfortable that the difference in production rates is due to the frac design. We’ve also drilled a couple of extended laterals probably in the 7000 to 8000 foot length that is currently underway. So we’ll look at the economics of that what kind of uptick we get from the extended lateral part of it. But it’s still little bit too early dated. We still have a lot of acreage outside of this one township that I would say would be in a similar geologic position. We just haven’t drilled the wells because it becomes real problematic. We don’t have the infrastructure down there yet. So since we’re really trying to define the economics of the play more so than just the geological part or geographical part of the play right now that’s where our focus is.

David Amoss - Howard Weil

Okay, got it. And then moving to the Marmaton, any update or better line of site on the timing when the legislature could move on allowing you to drill those longer lateral well?

Brad Guidry

Yes, we still think it’s in the May timeframe, David. There is nothing that’s changed from there but the legislature is in session. And we’re expecting some of kind of response by May.

David Amoss - Howard Weil

Okay great and then one final one. Any update on the leasing environment in the emerging play, is there anything left in the core that you can add at a reasonable cost? It sounds like is a lot held I that region but what the competitive environment out there look like?

Brad Guidry

Yes, it is definitely competitive. In the core region most of that lease holds held by production, so we’re negotiating a number of deals with operators that would allows us to farm in or some of kind drill the earn type commitment. And those aren’t big deals per se that you knock off big number of acreage, but it is available out there and we’ll work in that pretty hard. And then the second part of that is we’re being successful picking up lease hold and what we considered the expanded. And the expand is not so much but we see it differently it’s just not been de-risk and certainly has more risk and what we consider is the core, but looking at logs it appears to be somewhat comparable.

Operator

(Operator Instructions) we have a question online from Mr. Marc Bianchi from Cowen. Please go ahead.

Marc Bianchi - Cowen

With regard to the budget, can you talk little bit about we’ve seen commodity prices moves up here a little bit NGLs in particular important for us and that’s going to bring some more cash in the door and you’ve got a bunch of drilling opportunities out there throughout the course of the year where you may see some success? Can you kind of talk though the stock prices behind the budget right now? And how it could change over the course of the year depending on commodity price changes and drilling success?

Larry Pinkston

Marc, there is no question process today or higher than where we started with in our budget back in November. So cash flow should be higher for the year than what we’ve expected then. We always look at our budget pretty strongly this year. And usually we either adjusted up or down not significantly. But now we take into account what are, looks like, our cash flow going to be versus what we anticipate it to be. What kind of success are we seeing in the different deals on our EMP side? What’s the May for the drilling rig? So we take a pretty almost a serious look at it midyear as we do going into the year specifically want to adjust it for the second half. Thus far we’ve not adjusted it at all and not really anticipate looking at it seriously until midyear timeframe.

Marc Bianchi - Cowen

Okay and then on sort of follow-up to that. On service cost you guys mentioned benefiting from potentially some higher day rates on the drilling site. In terms of the services that you procuring and I’m thinking about frac and really anything else that would be in the DNC budget, are you seeing any of those prices move up?

Larry Pinkston

For 2014, prices have been relatively flat. We’ve seen reductions in ’12 and ’13. But beginning of this especially in the frac and really the other services, things have been pretty flat.

Marc Bianchi - Cowen

Okay. Are you anticipating anything to move up later on in the year or could?

Larry Pinkston

Maybe, I think, it really depends what the futures market with the gas does. I think if you get the point where gas for ’15 is in the 450 range then I think you could start to see that because I think demand will pick up and I do think there could be some slight. I’m not expecting anything major at all.

Operator

Our next question online comes from Mr. Blake Hancock from Howard Weil. Please go ahead.

Blake Hancock - Howard Weil

You guys are seeing a nice move here and activity given the start of 1Q, given the number of contracts that roll off here in 1Q and 2Q and what you’re hearing from customers, do you think that the 72, 73 active rate count do you expect by end of the quarter is maintainable? Or just help us understand what you guys are seeing for the rest of year as far as the drilling activity?

Larry Pinkston

Yes, frankly, we think it is maintainable, we’re certainly not seeing people thinking about going backwards, almost all of the conversations we’re having with operators are very forward thinking as to increase. So even though we don’t have all of those rigs on long term commitments, we stay in constant contact with those operators to know if we’ll have rigs available or not, so, it looks very promising, there’ll still be similar number to that quarter if not improving.

Blake Hancock - Howard Weil

No, that’s great, lot of help. Looking at the BOSS rig you got to know what’s reordering by the end of third quarter and plausibly fourth and, I know there’s some longer lead time items there, in the assembly of these rigs, are you guys going ahead and ordering some of these items ahead of contract, and now that the first BOSS rig is completed and you’ve worked through that process. In a perfect world how many of these rigs you think you could possibly build let’s just say next year in 2015.

Larry Pinkston

Probably 10-14.

Blake Hancock - Howard Weil

Okay that’s great and are you guys going ahead and ordering.

Larry Pinkston

The lead times, the worst lead times right now are about three to four months on items, and the more we get into the program, the easier it is to plan and to have that stuff online as we go.

Blake Hancock - Howard Weil

Okay.

Larry Pinkston

It’s starting but it’s certainly achievable.

Blake Hancock - Howard Weil

Okay, that’s great and just last one if I can, looking at the four rigs that you guys sold at the beginning of this year, is it fair to put a similar price on those for the ones that you sold here in 2013.

Larry Pinkston

Yes.

Blake Hancock - Howard Weil

Okay, and how many more of these larger horsepower rigs are you guys looking to get rid off and are there any opportunities to divest the lowest horsepower rigs that you guys have.

Larry Pinkston

Answer to the first part, we have no more 3000 horsepower rigs, we don’t have any more so we don’t have any more for sale, we have two other 2000 horsepower rigs but they’re not rigs that we were going to sell, the rigs now that will be getting our attention or trying to move will be in the smaller range, 500-600 horsepower mechanical rigs, that will be our goal to sell some of those this year.

Operator

(Operator Instructions) And this time I see we have no further questions.

Larry Pinkston

Thank you, Richard. I want to thank everyone for joining us this morning, we will be back on the road again in a couple of weeks and hope to see many of you all as we travel across the country, so appreciate your joining us this morning and that’s all we got.

Operator

Thank you ladies and gentlemen, this concludes today’s conference, thank you for participating, you may now disconnect.

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