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Executives

Larry D. Pinkston – President and Chief Executive Officer

Brad Guidry – EVP, Exploration for Unit Petroleum Company

John Cromling – Vice President and Division Manager

Robert Parks – President

David T. Merrill – Senior Vice President, Chief Financial Officer and Treasurer

Analysts

Marshall Adkins – Raymond James

Raymond Deacon – Brean Capital, LLC

Brad Evans – Heartland Advisors

Unit Corporation (UNT) Q1 2013 Earnings Call May 7, 2013 11:00 AM ET

Operator

Welcome to the Unit Corporation First Quarter 2013 Earnings Conference Call. My name is John 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, speakers’ will 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 D. Pinkston

Thank you, John. 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 take questions after the conclusion of their comments.

We’ve released first quarter 2013 results this morning. Adjusted non-GAAP net income for the quarter was $44.5 million or $0.92 per diluted share. Our non-GAAP financial reconciliation defined is net income, excluding unrealized value commodity derivatives as contained in our press release.

Our Oil and Natural Gas segment, total production during the first quarter was 4 million barrels of oil equivalents. Weather in the Oklahoma and Texas Panhandle has negatively impacted production. During the first quarter by approximately 50,000 barrels of oil equivalents, similar to the fourth quarter of 2012, we continue to experience ethane rejection throughout the first quarter.

The impact of ethane rejection reduced our first quarter total net production of approximately 90,000 barrels of oil equivalents. We foresee ethane rejection continuing throughout most of the year.

Total liquids production in the first quarter increased 16% over the first quarter of 2012. For Contract Drilling segment, our average number of drilling rigs utilized during the first quarter of 2013 increased 4% from the fourth quarter of 2012, we average 66 rigs utilized and increase from an average of 64 in the fourth quarter of 2012. We do not anticipate the significant change in utilization during the second quarter of 2013.

During 2013, we are building a new 1,500 horsepower AC electric drilling rig with the proprietary design. The rig is anticipated to be placed into service during the third quarter or fourth quarter of this year. Initially the rig will be utilized by our Oil and Natural Gas segment. John will have further comments on the new rig in a few moments.

During the first quarter of 2013, our Midstream segment completed the installation of the new 30 million cubic feet per day gas processing flat at its Bellmon system in the Mississippian play in North Central Oklahoma, bringing total capacity of the system to 55 million cubic feet a day. We’re excited about the growth potential of the Bellmon system given the significant amount of third-party acreage dedicated in this area.

We continued to expand our Marcellus gathering system to meet the needs of third-party producers. The Midstream segment continues to operate in ethane rejection mode where possible, which has reduced its volume of liquid sold during the first quarter. Overall, we are pleased with results of the first quarter. We are very optimistic about the remainder of 2013 with a number of opportunities, we’re seeing in all three segments.

At this time, I’d like to turn the call over to Brad to discuss our Oil and Natural Gas segment.

Brad Guidry

Good morning, I’ll go ahead and give an operations update for each of the four core areas. First, in the Wilcox play located in Southeast Texas will continue and have good results in the previously announced discovery of the Gilly Wilcox field. During this early phase of development, we are allowing sufficient time for testing multiple Wilcox zones and that will provide critical data for the most efficient way to ultimately produce the field.

To illustrate the potential with this discovery in our development strategy, let me take you through a brief look at the currently six producing wells. The first well has been producing for 21 months and during that time, its average 8.5 million cubic equivalent feet of gas per day and the well is still currently making 7.8 million per day. This is only an 8% decline over the 21 months and this well has not been fracture stimulated.

The second well is still online for 18 months, averaging 7 million cubic feet of equivalent per day, and the well was currently making a 7.8 million per day, which is actually an increase of 11%. Both of these wells are the only wells in the field completed in the prolific Wilcox Blackwood sand. However, this sand is protected throughout the field and is behind tight in the remaining four wells, which are currently producing from deeper Wilcox zones. These wells will be re-completed into the Blackwood zone sometime in the future.

All of the deeper Wilcox wells that we have tested are productive with varying results. Some of the zones appeared to be commercialized as vertical completions while others zones may achieve better economics as a horizontal well completion.

To test the concept, we’ve scheduled our first horizontal well to drill this summer, targeting one of the lower Wilcox sands. In addition to the existing producing zones, there are multiple potentially protected shallower Wilcox zones in the field that are behind pipe in all six wells with similar wall characteristics to the highly productive Blackwood sand. Plans are for 2013 to test several of these zones.

To summarize the Gilly Field, we estimate potential resource reserves of 262 Bcf gross and 168 net Bcfe to Unit. Based on that reserve estimate, we could potentially produce 50 million cubic feet of gas per day continuously over the next 14 years to deploy the field.

In addition in Gilly Field, about one mile north of the field, we discovered a new productive fault block by recently completing two wells from several different Wilcox sands. Further testing and additional drilling is scheduled for later this year to delineate the field size and the potential reserves.

Along trend to the East, approximately 20 miles, we’re continuing to analyze the production data on three wells that have been online since the end of last year. Preliminary results suggest these may be horizontal candidates but we need additional production data prior to drilling any future wells in that area.

I’ll move to the Mid-Continent area. In our Mississippian play located in south central Kansas, we anticipate the completion of the pipeline and processing facilities during the third quarter of 2013. Our plan at that time is to move the Unit rig back into the area and drill wells for the remainder of 2013 with one rig and the second rig maybe added in the fourth quarter.

Unit’s initial Mississippian well had first production in May of 2012 at an average 30-day rate of 350 barrels oil equivalent per day. It was consisted of 92% oil and liquids. Unit’s second well was completed approximately two miles from the initial well, it came online at the very end of 2012 and the 30-day peak rate on that was approximately 130 barrels oil equivalent consisting approximately 86% oil and liquids.

The Miss interval in both wells appeared similar in log character and shows; however, the second well had a smaller frac design, which we interpret as the main reason for the lower 30 day IP. Our plan going forward is to utilize larger frac design similar to what was pumped on the initial well; based on the production profile from both of these wells, the reserve range estimate remains at 125,000 MBoe to 180,000 MBoe.

Two additional wells have recently been drilled lack sufficient production data at this time and results will be reported at the second quarter earnings call. There are three remaining wells that have been drilled and are currently waiting on completion and the pipeline infrastructure.

Moving to the Marmaton horizontal oil play located in Beaver County, we’re continuing to see positive results since we’ve implemented 640 acre space in and optimize our pumping operations. First quarter production was up 94% over the first quarter of 2012 and up 3% over the fourth quarter of 2012 after adjusting for weather related production loss. We completed 10 wells during the first quarter with average working interest of 74%. A 30 day peak rate for the first quarter wells was approximately 390 barrels of oil equivalent per day, which is similar 2012 results and in line with our expectations.

The estimated ultimate reserves is unchanged from previous estimates at 120 to 130 MBoe per well. We currently have three rigs drilling in the Marmaton and the plans are to reduce down to two rigs in about 30 days and we’ll keep those two rigs in the play for the remainder of 2013.

In the Granite Wash play located in Texas Panhandle, our drilling phase has increased during the first quarter. We began the year with two unit rigs in the area. We added two more unit rigs during the first quarter. Our current plan is to add a fifth rig in a third quarter and potentially of six rigs in late fourth quarter.

We began drilling operations on our first horizontal Granite Wash well from the recent Noble acquisition in March and that’s on leasehold that was located approximately 18 miles from the Buffalo Wallow Field. We plan to spot our first well in the Buffalo Wallow Field at approximately one month and our expectations are to drill and test several different Granite Wash sands across the Noble leasehold during this year.

Our first quarter production in the Granite Wash was up 68% over the first quarter of 2012 and up 4% over the fourth quarter of 2012 after adjusting for weather-related production loss. Due to the reduction in drilling rigs during the fourth quarter of 2012, we had first sales on only four horizontal Granite Wash wells with an average working interest of 97%. The peak 30-day rate was 4.7 million of cubic equivalent per day, which again as in line with our 2012 results. For 2013, we’ve revised a number of completed wells to 30 at an approximate net cost of $140 million.

In summary, the E&P company is on track with our budget forecast and our production guidance. Our drilling activity is increasing, which should result in a greater number of completed wells and increased production during the second half of the year.

I’ll now turn the call over to John Cromling for drilling update.

John Cromling

Thank you, Brad. Our Contract Drilling segment experienced an improved first quarter with rig activity increasing slightly as it did throughout the industry. Day rates decreased slightly during the first quarter. The average day rate for the first quarter was $19,580 as compared to $19,828 for the fourth quarter. The average per day operating margin for the first quarter before the elimination of intercompany profits was $7,534, which is $304 per day decrease from the fourth quarter.

The largest factor in the decrease in average operating margins is due primarily to the day rates decreasing by $248 per day. The direct operating cost decreased by $111 per day for the first quarter as compared to the fourth quarter. Most of this decrease was due to lower workmen’s compensation related costs.

Our average rig utilization during the first quarter was 66.3 rigs, which is a 4% increase over the average for the fourth quarter. We began the first quarter with 63 rigs operating and ended the quarter with 68 rigs operating. Currently, we were operating 66 rigs with two additional rigs contracted, which will begin operations within the next couple of weeks.

During 2013, we will complete the construction of a new 1,500 horsepower AC rig, which will be a prototype for future expansion. This rig is a proprietary design that we’re in corporate features to move more efficiently and also the ability to walk a multi-well pads.

There are many other components of the rig that were permitted to exhale horizontal drilling, especially in the drilling fluid system. We will continue to refurbish rates as the market dictates and we expect much to this growth will happen in the 750 to 1000 horsepower range in the Mississippian play but certainly not restricted to this area. The combination of our inventory of available rigs, people and a strong financial base will allow Unit drilling to expand with market.

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

Robert Parks

Thank you, John. The Mid-Stream segment began the year with operating profit before depreciation and amortization of $8 million in the first quarter of 2013, up 24% compared to the fourth quarter of 2012. Our first quarter process volumes per day were down 1%, compared to the fourth quarter of 2012 for an average of 162,287 MMBtu per day.

The decrease in per day processed volume is mainly due to declines across our systems, which were not completely offset by additional well connects in the first quarter as well as severe winter weather causing freeze off cost in the field during February. Also our natural gas liquids sold per day decreased 5% from the fourth quarter of 2012 to an average of 420,291 gallons per day.

This decrease is primarily due to lower processed volumes and operating in ethane rejection mode for the entire first quarter of 2012 due to low ethane prices. Gas prices averaged $2.14 for the fourth quarter of 2012, compared to an average price of $3.21 for the first quarter of 2013, representing a 2% increase.

Liquid price is also improved by approximately 4% from the fourth quarter of 2012, compared to the first quarter of 2013. During the first quarter of 2013, we invested $22.4 million in capital projects. Majority of capital expenditure of core expansion projects related to our Bellmon and Pittsburgh Mills facilities, while remainder was spent on extension projects on several other gathering systems that primarily put in some cash. For 2013, we have budgeted total cash expenditures of $105 million.

I will now discuss areas of significant activity for the Mid-Stream segment. The Mississippian play in North Central Oklahoma remains a key focus – area of focus for the Mid-Stream segment. Our Bellmon facility currently consists of approximately 136 miles of pipeline, two processing plants with the total processing capacity of 55 million cubic feet per day and a 20 mile NGL pipeline connected to one of the facility in Medford, Oklahoma.

Producers in this area continued to be active and we are consistently connecting new wells to the system. We are currently processing approximately 30 million cubic feet per day of our plan as volumes continue to increase. In anticipation of increasing volumes in the area, we are planning to install an additional 60 million cubic feet per day processing plant by the end of this year. We are continuing to complete extension project and set temporary seat points for producers in the area.

Also in the Mississippian play, we are in the process of constructing a new gathering system and processing plant at Reno County, Kansas. This system is currently under construction and will consist of approximately 35 miles of gathering pipeline and compressor station and two processing plants that will provide initial processing capacity of approximately 28 million cubic feet per day. This system is expected to be operational in the third quarter of 2013.

Turning to the Appalachian area, we are continuing to expand our Pittsburgh Mills gathering system located in Allegheny County, Pennsylvania. The first phase of this project has been completed and consists of seven miles of pipeline and a compressor station. We are continuing to connect wells to this system and currently have 14 wells connected, which are flowing approximately 50 million cubic feet per day.

In addition to these wells, we’re scheduled to connect an additional four wells in the second quarter of 2013 with an expected total volume in the range of 25 million to 30 million cubic feet per day. With the addition of these four new wells, our total gathered volume will increase to approximately 75 million to 80 million cubic feet per day.

In summary, we are off to a strong start in 2013 as we continue to focus on our core areas. We are excited about completing expansions of our existing systems and beginning construction of new Greenfield projects. Additionally, we are continually exploring new areas in which to expand our business. The combination of these activities will position us well for future success as we continue to expand and grow our Mid-Stream business.

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

David T. Merrill

Good morning, everyone. We ended the first quarter of 2013 with total long-term debt of approximately $715 million consisting of $645 million of senior subordinated notes and $70 million of borrowings under our credit agreement, giving us to conservative debt to capitalization ratio of 26%.

The current borrowing base under our credit agreement, which was recently redetermined by our bank group, is $800 million. We have elected an available commitment amount of $500 million, resulting in approximately $430 million of availability at the end of the first quarter and we could have $730 million of availability under our current borrowing base.

For the Oil and Natural Gas segment for 2013, we have hedged approximately 8,300 barrels of oil per day of oil production and 100,000 MMBtu per day of natural gas production. The oil production is hedged at an average price of $97.94 and the natural gas production is hedged at an average price of $3.67. We also have been layering in some 2014 hedges, the details of which is included in our Form 10-Q that is being filed today.

The effective income tax rate for first quarter of 2013 was 38.5% and the current portion of income taxes was 10%. For 2013, our operating segment capital expenditures budget remains unchanged from the beginning of the year and $789 million excluding acquisitions.

Budgeted capital expenditures by segment are $586 million for the Oil and Natural Gas segment, $105 million for the Mid-Stream segment and $98 million for the Contract Drilling segment. The 2013 capital program is anticipated to be funded using internally generated cash flow and proceeds from non-core asset sales.

John, we would now like to open the call to questions.

Question-and-Answer Session

Operator

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

Marshall Adkins – Raymond James

Good morning, guys. It looks like what caused you a little bit on the E&P side. But on the rig side that margins were down pretty nice. I assume that current structural nature that trends probably going to continue. Could you give us a little color on what you expect to see there in terms of the daily rig margins?

John Cromling

Marshall, part of that decline has been because we put more of the smaller rigs to 750,000 horsepower rigs to work in Mississippi, and so they have less day rate and 1,500 horse power rigs have.

Marshall Adkins – Raymond James

So more of a mix issue than…

John Cromling

Exactly, but I do believe we are seeing even in the last week or two much more interest in the 1,500 horsepower rigs and the two rigs that we have contracted that I mentioned, those are both larger rigs with better day rates. So I don’t really see that the day rates are going to increase through out the second quarter like they did in the first quarter. And if we continue to be able to control our cost as we have, we should see margins increase slightly.

Marshall Adkins – Raymond James

Okay, that’s helpful. I see Bellmon first AC rig; help us understand how the market views the AC rigs versus the SCR’s that you have? And secondly, you mentioned, you have a few skid rigs and like a few walking rigs as well. Do you see a shift to retrofitting more your rigs for that capability?

John Cromling

I’ll answer your first part of the question. That is the perception of most operators and that’s what they desire, and you see with all of the drilling companies merged to the new bills in the last two or three years have been of that source and so, we’ll go to meet that demand. There will be some things incorporated in this rig design that, buyers waiting to this point. We think that we’ve been able to learn a lot of things from other people and incorporate all of those things in one package. So we think we’ll be at the leading edge to be able to compete.

Marshall Adkins – Raymond James

Are the SCR’s getting that much of lower rate for the equivalent horsepower, I’m saying?

John Cromling

Yes.

Marshall Adkins – Raymond James

Okay.

John Cromling

That seems to be apparent by the numbers of people announce, but their average day rates. So we think there is – the market evidently tells us that there is that much difference. So that’s what we will try to give.

Marshall Adkins – Raymond James

Okay. And then the second part of the walking rigs, do you see more of that coming down or you set there?

John Cromling

Yeah, sir, because the reason it gives the operator a lot more flexibility if we have a walking rig rather than a straight line skidding rig. There is still a lot of places that the straight line merge fine. But as we have installed any kind of skidding system in the last two or three years outside of a couple, very exceptions they’ve all been a walking systems comes and allows operator to not to have to worry so much, but having every well in exact line and it gives you more ability to adapt to the wells bring off-line, not even accounting where they wanted to drill two rows or three rows of wells.

So it just makes sense to do that and that’s what we’ve been doing on the other rigs and we’ll continue to do that. Your question about whether we’ll retrofit some rigs with the AC systems, that’s a possibility, but probably in the near future as the next year, we’ll be mainly concentrated on building new rigs because there are so many other aspects of the rig, precise just it being AC or whether it has a walking system that we think we’ll give us an advantage.

Marshall Adkins – Raymond James

All right. Thank you, John. I appreciate it.

Larry D. Pinkston

Related our plans on the new rig is to build the one this year, operate it for a two or three months for sales in our E&P program, most of the big investment and the new builds, it would a 2014 kind of current track, now we’re not planning on beyond the one. We didn’t completed and operated a well before we start building for additional ones.

Marshall Adkins – Raymond James

Okay, thanks Larry.

Operator

Our next question comes from Ray Deacon from Brean Capital. Please go ahead.

Raymond Deacon – Brean Capital, LLC

Yeah. Hey, good morning. I was wondering if you could talk a little bit more, Brad, about the Mississippian and the three wells here that are waiting on completion, because I missed one those are going to come online and given the variability in the IP rates, or the decline rates to the end up being different and was there anything, you think they can have kind of move the average well up to kind of that 180,000 Boe level?

Brad Guidry

Yeah, Ray I mean we’re still very, very early on the coal production cycle for determination the EUR’s out here. The initial well was then on since May and the decline on it, it look like it had been established pretty well. We had some pump issues that came down now, that that resolved in the wells coming back up to our curve where it would put it to the middle, certainly to the upper end of our projections out there. We’re very pleased with what we’re seeing in the production from that well.

The second well, we drilled out there, we frac that using a packer system whereas first well was perf-and-plug. We did a frac job on the first well. Second one was smaller. And that well didn’t come on as high of rate, but we saw a flatter decline in it. But then we also have some pumping operation issues on that. So when these wells go down from parts, it takes a while, getting back up which of course it takes longer and get a better feel of what ultimate EUR and these are to get a good curve like you can trust for ultimate declines.

The third well we drilled, it came online at the end of last year, but that well was only completed from seven stages in the well we had eight different additional stages at time we initially frac that. We had some operational issues. So we elected just to produce some for seven as it affected the rate from that below what we had seen, because it was only half of the well. We just recently within the last two or three weeks frac the remaining stages with lots of frac design and that well will be put online. We have a fourth well that just went online two to three weeks and it is producing and we’ll talk about that at the next earning call.

The remaining three wells, they expect to have two of those three online here in the next month having stripped it rate, the process and facilities will not be in probably till July. So you won’t have a full rate on those wells sometime after that. But we do have a pipeline availability that we can produce those wells that is probably starting in the next three or four weeks. So we’ll get a little bit of early looking that. And then will start drilling back in July.

Raymond Deacon – Brean Capital, LLC

Okay, got it. Great, okay, thank you.

Operator

Our next question comes from Brad Evans from Heartland Advisors. Please go ahead.

Brad Evans – Heartland Advisors

Hey, good morning everybody.

Larry D. Pinkston

Hi.

Brad Evans – Heartland Advisors

Thank you for taking my questions. You don’t have to know where you had exit rate productions on E&P side at the end of the first quarter, do you?

David T. Merrill

The exit rates at about 260 million cubic equivalent per day. I don’t get the exact number, 256,109.

Brad Evans – Heartland Advisors

Okay. Could you speak broadly about how you see the demand curve rigs playing out over the next month or next quarter or two?

David T. Merrill

We don’t see much change right now Brad, through the second quarter. The thing that is that I am pretty optimistic about is kind of also just what we saw last year, last year we start off good, strong rig demand, operators got their drilling programs done early prices, liquids and gas prices remote to price than we had a big drop off in the second half of this year. Well, this year with gas price is being where they are and if they stay in this $4 range for the next three or four months operators are going to have a whole lot more cash flow, cash available on their hands and the industry is not known to pay down debt when it has extra cash flows.

So, pretty good that they will spend that money back into their exploration program. So we could see a pick up in the second half of this year, if gas prices will stay in the $4 range. I don’t think many of us were using $4 gas prices in our $4 gas for 2013. So I’m kind of optimistic about the second half. Second quarter is going to be pretty flat with the first quarter.

Brad Evans – Heartland Advisors

And Larry how many rigs are you marketing today?

Larry D. Pinkston

We’re marketing them all.

Brad Evans – Heartland Advisors

You are.

Larry D. Pinkston

It is basically no demand right now for the real small rigs. The 500, 600 horsepower and smaller, the big rigs are still depressed. But we do have the one 4,000 horsepower rig; it’s still operating under contract. But the demand still ease in the 750 to 1,500 horsepower range.

Brad Evans – Heartland Advisors

Very good, and then just from your perspective on the E&P side, what’s your thought process in terms of what will take free to perhaps to accelerate natural gas activity?

Larry D. Pinkston

Well, I mean what’s going to determine that is the economics of the gas drilling verus either rich gas or oil drilling and that I mean we are continually asked, “What’s that magic number when you start drilling gas wells?” Well, it may kind of depends on what the price of oil is and what kind of rate of returns you are getting on the rich gas or oil fields.

When you’re getting 50%, 60% rate returns, you’re not going to stop drilling those kind of wells to drill gas wells, even though they maybe getting 30% rate of returns. Now not all operators have choice, I mean they’re more limited to dry gas drilling and certainly they’ll pickup some rigs, more rigs as gas prices allow them to have more cash flow to invest. But as a whole for the industry, I think it’s going to be a rate of return analysis is to where can I invest your money to get a biggest bank.

Brad Evans – Heartland Advisors

Okay. And then just lastly from me, just I know you don’t guidance. But just listening what you said in terms of the margin dynamic on the land rig side and perhaps on the upstream side, maybe together with your – on the Mid-Stream piece of your businesses. It sounds like the first quarter should be probability and in EBITDA perspective of the lowest quarter of the year, assuming commodity prices maintaining current levels?

David T. Merrill

Yeah, thanks. The gas prices stay in the $4 range versus where kind of add today. I would expect EBITDA and cash flow to grow during the year versus the first quarter, but I just assuming oil prices to stay in a $90 plus range. But we should see more rigs go back to work with our gas prices, so…

Brad Evans – Heartland Advisors

Lot of assumptions there, but I appreciate the color. Thank you.

David T. Merrill

Okay.

Operator

(Operator Instructions) Our next question comes from Marshall Adkins from Raymond James. Please go ahead.

Marshall Adkins – Raymond James

I figure that just go or I mean I’ll have some more of your time here for me.

Larry D. Pinkston

It sounds good.

Marshall Adkins – Raymond James

SG&A and depreciation were a little bit lower than we were modeling. Can you help us with that Dave in terms of what we all be thinking for next quarter and the rest of the year?

David T. Merrill

SG&A, SG&A should be – it will grow a little bit, but not much, but where we are in Q1. And Q1 tends to be a little higher in some instances, but there will also be some additional head count ads throughout the course of the year. Depreciation, beyond depreciation, it depends on what’s you’re looking at while. We continue to add in the mid-stream area, assets and put it in the operation so. Depreciation not a part of grow, not in big jumps, but it out to be in growing a little quarter-to-quarter.

On the rig side as utilization stays relatively flat where it is. We shouldn’t see much of a change in depreciation there and then on the E&P side of course, it’s going to be dedicated on what goes on with the certainly production, but also our DD&A rate will be up just a bit probably as we continue to move further course of the year.

Marshall Adkins – Raymond James

So model a modest improvement DD&A over the increase and DD&A as we go through the rest of the year and SG&A up, but not a whole lot?

David T. Merrill

Correct.

Marshall Adkins – Raymond James

Okay. You went through some of those CapEx numbers, but you go through them pretty fast. So could you just rehash those for me to make sure erode them down right?

David T. Merrill

Sure, the overall corporate operating segments CapEx was $789 million and that breaks out $586 million on the E&P side, $105 million on the Mid-Stream side and $98 million on the Contract Drilling side.

Marshall Adkins – Raymond James

Okay, so...

John Cromling

Marshall, as we did typically, as we approach midyear, we’ll kind of reevaluate what’s going on commodity price buys and opportunity buys and revisit our capital program with our Board and then let everybody know if there is an adjustment one way or the other or if we hold of course.

Marshall Adkins – Raymond James

So the $98 million on the rig side will be that one new AC rig plus basically maintenance and upgrades of other stuff?

John Cromling

Yeah, that is correct.

Marshall Adkins – Raymond James

Okay. Excellent, guys. Thank you, all.

David T. Merrill

I appreciate it.

Operator

Our next question comes from Ray Deacon from Brean Capital. Please go ahead.

Raymond Deacon – Brean Capital, LLC

Yeah. Hey, one more question for Brad, I was wondering, can you repeat what you said about your ability to keep gas production flat in the Wilcox?

Brad Guidry

Just significance of a discovery in 262 Bcf gross reserves, that’s the equivalent of 50 million a day for 14 years.

Raymond Deacon – Brean Capital, LLC

Got it.

Brad Guidry

In the field; so it just really away to share the overall significance in that discovery.

Raymond Deacon – Brean Capital, LLC

Right. And lot of it, you will not require a new wells right, because you’ll be just moving up zone to other?

Brad Guidry

That the field, we’re still delineate the full size of the field. We have six wells drilled now. And early on we estimated to take about 10 wells, it maybe about 12 wells now and that pretends a little bit if we can give to all of the zones and the existing wells.

There maybe some acceleration wells we want to drill. There is several zones up above where we’ve completed any of these wells, it look spectacular and then look as good as our main Blackwood sand that we’ve talked about and there are so many stake pays of these wells typically when you complete and we want to starting the model and workout, because it’s very problematic to complete at a deeper depth once you’re completing from the shallower zone.

So that’s one of things we want to workout. We want to drill these four more wells, take a look at the best way, how do we develop this field of certainly the horizontal well that we’re going to drill in the field and one of the deeper zones has a whole another dimension to the potential of the field, so there is a lot of years of drilling here to take a look at it, where re-completion. There will be the drilling and the re-completion that essentially will be ducktail together.

Raymond Deacon – Brean Capital, LLC

Got it, got it. Okay, I guess just two other quick ones, any update on the process of changing the spacing rules, so that you can feel the longer, laterals in and any you can point to that makes you more optimistic about NGL prices?

Larry D. Pinkston

Yeah, the legislator, I don’t know that a bill has been proposed yet, but that’s certainly been discussed in the legislator or general counsel, which is kind of ramp rounding the whole process is in Oklahoma City today and another meeting with legislature.

So yeah we’re optimistic that we’ll make progress really where we get that entirely this year. That’s still probably a 50-50 deal that we are making progress towards that and I think yeah, we eventually get there. It might not beyond the statewide basis, but may have to back half towards on field by field basis, which is okay, if that’s where it ends up that that yeah, it still being worked very vigorously.

Raymond Deacon – Brean Capital, LLC

Got it.

Larry D. Pinkston

Liquid prices, here the question, I don’t see short-term. Yeah I mean, it’s going to be very cyclical and inventories get work down, you’ll see some improvement in liquid prices and there will be projecting ethane and then liquid prices will go back down again, and so still we fix the demand side, which the main side of my opinion is going to be a 2015, 2016 kind of scenario or we going to see sustained higher ethane prices, which is really the only liquid component that’s under pressure right now. In the meantime, it’s going to be cyclical, you don’t have ups and downs, you’ll have periods, we don’t reject and then periods when you do rejects. So I think that will kind of be the mode for the next couple of years.

Raymond Deacon – Brean Capital, LLC

Okay got it.

David T. Merrill

Thank you.

Operator

Our next question comes from Brad Evans from Heartland. Please go ahead.

Brad Evans – Heartland Advisors

Yeah I was just curious what needs to happen if you get to the high-end of your guidance on the production front?

David T. Merrill

Yeah Brad, I mean I think we’re in pretty good track to get there. I know first quarter was certainly lower than you guys probably expect it. We knew, when we would acquire Noble, and we slowdown our drilling rate at that time, I mean our forecast for this year was we would have a little bit of low in the first quarter. Part of the exit rate, I was talking about I mean that included the weather production loss that we had, which was primarily in the March event.

So if the production itself, I’m giving you the financial exit rate in that, not necessarily the production rate borrowing wherever issues out there. But I think with the rig schedule that we have, the results we’re seeing, I’m hopeful that we will be at the high-end of our guidance.

Brad Evans – Heartland Advisors

Thank you for that. And just in terms of the non-core asset sales. Is there any update there in terms of any progress or just an update, it will be helpful there?

John Cromling

We are progressing, it’s in process of course as we mentioned earlier, we will be fitting our additional Bakken prospect that for a non-operated interest up there. It’s in process. We have a meeting going on currently on it. But I think we’ll have a resolution of it in the next three to four months and we’re looking at a couple of other smaller kind of packages than what it would be, but they’re all kind of in process right now.

Brad Evans – Heartland Advisors

And just on the buys side, Larry, I imagine I mean there is, is I understand there is a lot of asset in the market, but it seems particularly robust right now. And what’s your appetite for dry gas asses at this point, I need an acquisition front?

Larry D. Pinkston

Yeah, it’s all price determine. You buy that of our price and we’re very interested that again it comes back to or kind of rate of return and we’re not prepared yet to use $5 and $6 gas pricing in our economics that if we can get above to that price we would be very interested.

Brad Evans – Heartland Advisors

Okay, very good, thank you.

Operator

We have no further questions at this time. I will turn it back to Mr. Pinkston for closing remarks.

Larry D. Pinkston

Thank you, John. Thanks everyone for joining us this morning and thank you for those questions. Good questions and we appreciate those. And we look forward to seeing many of you over the next couple of months. I think that conclude this call. Thank you.

Operator

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

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