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Executives

Larry Pinkston – President and CEO

Brad Guidry – EVP, Exploration for Unit Petroleum Company

John Cromling – EVP, Drilling for Unit Drilling Company

Bob Parks – President, Mid-Stream

David Merrill – SVP, CFO and Treasurer

Analysts

Jim Rollyson – Raymond James

Brian Velie – Capital One

Phillip Jungwirth – BMO Capital Markets

Ray Deacon – Brean Capital

Unit Corporation (UNT) Q4 2012 Earnings Call February 19, 2013 11:00 AM ET

Operator

Welcome to the Unit Corporation Fourth Quarter and Year End 2012 Earnings Conference Call. My name is John and I will 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.

This conference call contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act. All statements other than statements of historical facts included in this call that address activities, events or developments that the company expects or anticipates will or may occur in the future are forward-looking statements.

Several risks and uncertainties could cause actual results to differ materially from these statements, including: the impact that any decline in wells being drilled we’ll have on production and drilling rig utilization; the productive capabilities of the company’s wells, future demand for oil and natural gas, future drilling rig utilization and day rates; projected growth of the company’s oil and natural gas production; oil and gas reserve information, as well as the ability to meet future reserve replacement goals; anticipated gas gathering and processing rates and throughput volumes; the prospective capabilities of the reserves associated with the company’s inventory of future drilling sites; anticipated oil and natural gas prices; the number of wells to be drilled by the company’s exploration segment; development, operational, implementation, and opportunity risks; possible delays caused by limited availability of third-party services needed in the course of its operations; possibility of future growth opportunities and other factors described from time to time of the company’s publicly available SEC reports.

The company assumes no obligation to update publicly such forward-looking statements whether as a result of new information, future events, or otherwise.

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

Larry 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. Then we’ll take questions after the conclusion of their comments.

We released fourth quarter 2012 and full-year 2012 results this morning. After the effect of a non-cash ceiling test write down, we reported a net loss for the fourth quarter of $56.5 million, or $1.18 per diluted share. With the effect of the ceiling test write downs for 2012, we reported net income of $23.2 million, or $0.48 per diluted share.

As noted, the ceiling test write down does not impact cash flow, the write down resulted from substantially lower natural gas and natural gas liquid prices. Excluding the impact of the write down, fourth quarter net income would have been $47.9 million or $0.99 per diluted share for the year. Excluding the ceiling write downs, net income would have been $199.8 million or $4.15 per diluted share, a 2% increase over 2011.

As noted, 2012 was a year in which we faced strong commodity price headwinds. The year was also one in which we had significant accomplishments in all three of our business segments and a number of meaningful transactions that were brought to fruition.

In our exploration and production segment, we ended 2012 with total proved reserves of 150 million barrels of oil equivalent, a 29% increase over 2011. We replaced 337% of 2012 production with new proved reserves. We completed a very significant acquisition of approximately $600 million from Noble Energy, bolstering one of the core areas with many years of future drilling locations.

We announced a very significant discovery in our Wilcox play, which we believe house 160 Bcfe net resource potential for us. We also completed the divestiture of two non-core asset packages generating net proceeds of approximately $270 million.

In our contract drilling segment, we were able to place two new build rigs into service and we sold one 600 horsepower mechanical drilling rig. As I’ve noted on the third quarter call, we’ve seen some softening in the rig demand in the fourth quarter. By the end of the fourth quarter, we had 63 rigs operating. We have seen an uptick in rig utilization in the first quarter of 2013, which John will discuss shortly.

In our midstream segment, we added 45 million cubic feet per day additional natural gas processing capacity at our capital Hemphill plant, which has increased total capacity to 160 million cubic feet per day. This plant is in the Granite Wash play, one of our core areas for both our exploration and production and contract drilling segment. We also completed the construction of our Bellmon processing system and the emerging Mississippian play. We continue to add to this gathering system and connect new wells.

Our midstream segment currently has – we currently have the capacity to process 280 million cubic feet per day throughout our midstream segment. Ethane prices during the second half of the year had a significant negative impact to our Midstream and oil and gas segment. The process has recovered somewhat thus far in 2013.

We’re firmly convinced that our diversified approach to our oil and natural gas business is one that enables us to allocate capital to opportunities in which we see the greatest value. The cycles for growth in each segment are often times different. However, our structure enables us to aggressively pursue the opportunities when the cycle occurs.

A good example of this is that in 2012 we had total capital expenditures in excess of $1.3 billion including acquisitions, yet we completed the year with a very conservative debt to capitalization ratio of 27%. We have had several major accomplishments in all three of our business segments during 2012. In 2013, we will be celebrating the 50 anniversary of Unit. We’ve built this company for the long haul, one in which we will continue to be focused on building value for our shareholders.

At this time, I’d like to turn the call over to Brad to review our exploration and production segment.

Brad Guidry

Good morning, everyone. I’m going to start out today with our newest core play, the Mississippian. This is the first time we’ve talked about this play, so we’re excited to be able to do that. We’ve recently acquired about 105,000 net acres, which is located primarily in Southern Kansas. We drilled our first horizontal well in Reno County, Kansas, in the second quarter of 2012 to a total measured depth of approximately 8,000 feet, which includes 3,850 feet of lateral. The well was frac’ed in 11 stages with approximately 1.1 million pounds of sand, 32,000 barrels of water and the first production occurred in May of 2012.

The average peak 30-day rate was 352 barrels of oil equivalent per day and that consists of 89% oil, 3% natural gas liquids, and 8% natural gas. The average daily water rate during the IP 30 period was approximately 1,750 barrels of water, which is being disposed into the Unit Saltwater Disposal system.

With the limited production date available in this area of the Miss, we primarily used the production profile from our initial well to project the ultimate reserves for the Miss play in this Kansas area. That range is between 125,000 Mboe and 180,000 Mboe. Using this estimated range of completed costs of approximately $3 million along with flat pricing of oil at $90, gas at $325 and NGLs at $30, the typical Miss well would have a calculated rate of return of approximately 30% to 66%.

In addition to the initial well, we drilled three more horizontal Miss wells in the second half of 2012. Two of the wells had first sales in late December of 2012, and the third well is currently waiting on pipeline connection. In the first quarter of 2013, we’ve just finished drilling three additional Miss wells and we plan to take a break from drilling for three to four months until the pipeline infrastructure is installed in approximately June of 2013.

To summarize, we have drilled seven Miss wells to date with three of the wells currently producing. A fourth well is going to sales in the upcoming weeks and the remaining three wells will be shut in until the pipeline completion. Our current plans are to move the Unit drilling rig back into the Miss play in July of 2013 and possibly add a second Unit drilling rig in September of 2013.

We anticipate this program will result in approximately 13 gross wells being drilled and online by the end of 2013. With our current leasehold position of 105,000 net acres, we estimate approximately 300 potential Miss locations based on a 320-acre spacing. The estimated spending for the Miss in 2013 is approximately $40 million net for drilling and completion.

Moving to the Marmaton play located in Beaver County, Oklahoma, we achieved record production for the third consecutive quarter during the fourth quarter of 2012 with production increasing 15% over the third quarter of 2012. For the year, our production has increased 61% as compared to 2011. For 2012, we had first oil and gas sales on 32 operated horizontal Marmaton wells, including two extended lateral wells, with an overall average 30-day IP rate of 407 barrels oil equivalent per day. This is a 32% increase in the IP 30 rate as compared to 2011.

One factor that has contributed to both the increased IP 30 and the increase in the overall field production is the recent development of several new areas of the field with better than average results. A second factor is the optimization of the individual well production by effectively modifying the pump operating conditions to minimize downtime and costly workover operations, which has resulted in the wells having more consistent production.

Although we’re pleased with production growth from our Marmaton play, we have recently recognized varying degrees of wellbore interference in the field. In general, the wellbore communication has been more prominent in wells that are spaced closer than one mile apart and in those areas that are more highly fractured. Wells in these areas have experienced greater downtime and a steeper decline, which has adversely affected the estimated ultimate reserves. Although it’s still too early to predict the ultimate effect of the well interference, we have adjusted our overall existing Marmaton reserves downward by 22% at the end of fourth quarter 2012.

However, going forward, we made several operational changes to manage the effects of this communication. First, current plans are to space our new wells approximately one mile apart to minimize potential well communication. Secondly, we are modifying our frac design to allow pumping fracs at lower treating rates, which should reduce the effects of the potential communication. Third, we are currently testing the feasibility of simultaneous fracs on two offset wells with the goal to try to minimize the interference between the wells.

Most of these operational changes were put into place during the fourth quarter of 2012 and we’re already seeing a positive response from these changes. The 30-day IP for our fourth-quarter wells was 477 barrels of oil equivalent per day, which is the highest 30-day rate we’ve had for a quarter to-date.

The estimated reserves for the fourth quarter wells and for our future drilling wells are approximately 120 MBoe to 130 MBoe, which is still in line with our previous reserve estimates prior to the reserve reduction. Using the current AFE cost, $2.7 million and the flat prices of $90 oil, gas $3.25 and NGLs at $30, the calculated rate of return is approximately 80% to 100%.

The projected rate of return is actually higher for the equivalent EURs than the past, because of the improvements made to the well production operating conditions. Due to the spacing limitations with drilling extended lateral wells, our plan for 2013 is to drill the majority of our wells as short laterals. If different legislation is adopted, we will reevaluate our drilling program for extended laterals.

For 2013, we anticipate running two drilling rigs in this play and a third rig for short period of time, which should result in first oil and gas sales of approximately 40 wells at an estimated net cost of approximately $90 million. We currently have leases on approximately 112,000 net acres in the play with approximately 44% of that leasehold being held by production. Based on one-mile spacing, we have approximately 150 potential locations with an estimated working interest of 50%. We’re continuing to pursue opportunities to add to this leasehold position.

I’ll now move to the Granite Wash located in the Texas Panhandle. For 2013, we have first sales on 29, – I’m sorry for 2012, first sales on 29 gross wells, which is an 81% increase in the number of wells completed as compared to 2011. As a result of this increased number of completed wells, Unit’s net production for 2012 was up 41% as compared to 2011. The current production in the Granite Wash is approximately 87 million cubic feet equivalent per day and that consists of approximately 46% oil and liquids.

The Granite Wash laterals that we completed in 2012 targeted seven different Granite Wash lenses with 31% of the laterals being drilled in the Granite Wash B interval. Currently, we have three Unit rigs working in the Granite Wash with plans to add a fourth Unit rig in April and then a fifth Unit rig this summer and possibly a sixth Unit rig near the end of this year.

Although natural gas and NGL pricing remains weak, our current economics for the Granite Wash are still favorable using the flat pricing of $90 oil, $3.25 gas and $30 NGL and a completed well cost of $5.3 million, the anticipated reserve range of 3.5 Bcf to 4 Bcf, the calculated rate of return for Granite Wash wells was approximately 49% to 71% for that reserve range.

We anticipate spudding the first well on our newly acquired Noble leasehold in the late first quarter of this year, and general location of the rigs will be split between the acreage acquired from Noble and the existing Unit leasehold; however, we will have the flexibility to move the rigs as needed to either areas since the majority of our leasehold was held by production.

One of our goals for 2013 is to drill sufficient number of horizontal wells into the lower Granite Wash sands in the acquired Noble Buffalo Wallow Field to determine the economics and reserves for those sands. Once we have that established, we will develop a program to utilize pad drilling in 2014, which should both accelerate drilling wells and reduce well cost. We currently have leases on approximately 46,000 net acres in the Granite Wash, on which we’ve identified approximately 800 potential horizontal locations. For 2013, we estimate spending approximately $150 million net on drilling Granite Wash wells.

In the Wilcox play located in Southeast Texas, we’re continuing to successfully develop the previously announced discovery of the Gilly field, which is the significant multi-zone Lower Wilcox field with estimated potential resource reserves of 242 Bcfe gross and 168 Bcfe net. This is an increase of approximately 6% in the total net estimated reserves for the field as compared to the third quarter. At year end 2012, there were five producing wells in the field and those five wells had an average of 255 feet of potential oil and gas pay that are contained in eight separate Wilcox sands. Currently only three of those eight sands have been put on to production.

The five wells have an average net estimated proved reserves of approximately 6 Bcfe per well with an additional 7 Bcfe per well of resource reserves. This totals to 13 Bcfe per well at a completed well cost of approximately $6.9 million, which includes $1.5 million to add several Wilcox behind pipe zones in each well. The estimated finding cost for the field wells is approximately $0.50 per Mcfe. This is outstanding finding cost even for dry gas but this production has added bonus that oil and gas liquids account for approximately 42% of the reserves.

In the Gilly field for 2013, we plan on drilling a total of seven new field wells, which consist of five infill wells and two step-out wells designed to potentially expand the size of the field. Along the trend to the East, approximately 20 miles we’ve drilled two exploratory, one development Wilcox wells that encountered several potential oil and gas pay sands. All three wells are currently producing and we’re in the process of fracking several additional pay zones in the wells to determine the overall economics of this new area.

We plan to monitor the production and evaluate the economics on the three wells over the next several months prior to any additional drilling. We’re also continuing to review and define Wilcox areas that could potentially be good locations for horizontal drilling. Our current expectation is to drill our first horizontal Wilcox well in late 2013.

Overall in the Wilcox play for 2013, we plan to run one Unit rig, which should equate to approximately 12 gross wells, which include the 7 Gilly wells in the Gilly field and then five additional wells in various prospects. Our estimated next net drilling cost for the Wilcox is approximately $60 million.

In summary, 2013 looks very promising for our drilling program. Our current plan is to focus primarily in our core plays, where we anticipate spending approximately 76% of our budget drilling operated wells in the Granite Wash, the Marmaton, the Mississippi and our Wilcox plays. We are continuing to build our leasehold position in each of these plays, which should provide multiple years of drilling opportunities in each one.

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

John Cromling

Thank you, Brad. Our contract drilling segment experienced a challenging fourth quarter with rig activity decreasing as it did throughout the industry. Day rates decreased slightly during the fourth quarter. The average day rate for the fourth quarter was $19,828 as compared to $19,989 for the third quarter. The average per day operating margin for the fourth quarter before the elimination of intercompany profits was $7,838, which is $1,834 per day decrease from the third quarter.

The largest factor in the decrease in average margins is due primarily to the differences in non-day work related revenue, which was $1,289 per day less than the third quarter. During the third quarter, we had early termination fees equating to $1,007 per day. And during the fourth quarter, they averaged only $24 per day for a reduction of $983 per day.

The direct operating costs increased by $545 per day for the fourth quarter as compared to the third quarter. Most of this increase was due to increases in workmen’s comp cost, reimbursable crew bonuses and the expense of stacking its rigs. The daily expenses associated with the rig operations and the daily indirect expenses decreased during the fourth quarter.

Our average rig utilization during the fourth quarter was 64 rigs, which is 13% less than the average for the third quarter. However, most of the decrease had already occurred by the end of the third quarter. We began the fourth quarter with 66 rigs operating and ended the quarter with 63 rigs operating. Our rig utilization has increased since the end of 2012. We are currently operating 68 rigs with two additional rigs contracted, which will begin operating within the next couple of weeks. During 2012, we were able to refurbish several rigs and put them into service, especially in the 750 to 1,000 horsepower range. Most of these rigs are active in expanding Mississippian play in Northern Oklahoma and Kansas.

During 2012, we’ve established a solid workforce and continued to improve our safety culture for the year, which positions us well to continue to grow in 2013. We have several more rigs scheduled for upgrades, and we’ll proceed with these plans as the market dictates. The combination of our inventory of rigs, equipment, people and a strong financial base will allow Unit to expand with the market.

I now turn it over to Mr. Parks for the operating update.

Bob Parks

Thank you, John. The midstream segment completed a successful year and continues to be very active in several core areas. In the fourth quarter of 2012, we increased our processed volumes to 163,173 MMBtu per day, which represents a 4% increase over the fourth quarter of 2011. Also in the fourth quarter of 2012, we increased our gathered volumes to 325,231 MMBtu per day, which represents a 26% increase over the fourth quarter of 2011. Liquids sold volumes were 441,973 gallons per day, which represents a 14% decrease from the fourth quarter of 2011. This decrease is primarily due to operating in ethane rejection made due to low ethane prices late in 2012.

The midstream segment’s operating profit decreased 16% from the fourth quarter of 2011, primarily due to lower liquids volumes recovered and lower prices. Gas prices averaged $3.32 per MMBtu in the fourth quarter of 2011, a decline to an average price of $3.14 per MMBtu in the fourth quarter of 2012 representing a 5% decline. Liquids prices were also lowered by approximately 11% from the fourth quarter of 2011 compared to the fourth quarter of 2012.

Ethane prices fell from an average of $0.34 per gallon in the fourth quarter of 2011 to an average of $0.18 per gallon in the fourth quarter of 2012, a 47% decline, which affected our processing margin, since ethane represents the largest liquid component recovered at our facilities.

During 2012, we incurred capital expenditures of $183.2 million as compared to $79.3 million in 2011. Included in the $183.2 million are four new gathering systems we acquired in conjunction with Unit Petroleum’s acquisition from Noble Energy. For 2013, we have budget capital expenditures of approximately $105 million.

I will now discuss areas of significant activity for the midstream segment. In the Mississippian play in North Central Oklahoma, we are very active and remain the key area of focus for the midstream segment. In 2012, we spent approximately $56.8 million completing the initial phase of our new Bellmon gathering system, which is located in Noble and Kay Counties in Oklahoma. This facility includes approximately 83 miles of pipe, a 25 million cubic foot per day rental processing plant, which we are in the process of upgrading to an owned 30 million cubic foot per day turbo expander plant in the first quarter of 2013, and a NGL pipeline from our system to one of the liquids facility in Medford, Oklahoma. We are continuing to complete extension projects and set central receipt points for producers that continue to remain active in the area.

In the Appalachian area, we’re continuing to expand our gathering systems in the Marcellus shale play. Even though our focus has been on dry gas, we’re continuing to expand our gathering systems to keep up with third-party drilling activities. In 2012, we spent approximately $26.2 million completing the installation of seven miles of pipe on our Pittsburg Mills system that extends our system north to the next well pad.

From this well pad, we connected four new wells in the fourth quarter of 2012 bringing the total wells connected to the system to 10. The producer is currently drilling the next two well pads and we anticipate connecting an additional nine wells from these pads in the first half of 2013. This producer has plans to maintain a steady drilling schedule for the rest of 2013 and into 2014.

In summary, we continue to focus on our core areas, completing expansion of existing systems and undertaking new development projects. Additionally, we are continually exploring new areas in which to expand our midstream business. Both of these activities will 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

Thank you, Bob, and good morning. As has previously been highlighted by the management team, 2012 was the year of significant transactions and accomplishments in all three of our business segments. With all of the transactions completed during the year, we ended 2012 with total long-term debt of approximately $716 million consisting of $645 million net under our senior subordinated notes and $71 million of borrowings under our credit facility, giving us to conservative debt to capitalization ratio of 27%.

Our current borrowing base associated with the credit facility is $800 million and we have elected an available commitment amount of $500 million, leaving us with approximately $425 million of availability at year-end and $725 million of availability associated with our current borrowing base. As discussed in the third quarter earnings call, beginning in October 2012, any new hedges, we enter into would not be designated as cash flow hedges and the change in fair value for new commodity hedges from that point forward would be reflected in current earnings.

For the oil and natural gas segments for 2013, we have hedged approximately 8,300 barrels 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 $3.63. We also have from 2014 hedges in place for oil, the details of which will be in our Form 10-K to be filed next week.

The effective income tax rate for 2012 was 41.2% and we currently estimate the rate for 2013 to be 39%. The current portion of income taxes is estimated to be approximately 10% to 15% for 2013. Also for 2013, our operating segment capital expenditures budget is $789 million, a 6% increase over 2012, excluding acquisitions. Budgeted capital expenditures by segment are $506 million for the oil and natural gas segment, $105 million for the midstream 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 turn the call over and open it for questions.

Question-and-Answer Session

Operator

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

Jim Rollyson – Raymond James

Good morning gentlemen.

Larry Pinkston

Good morning.

Jim Rollyson – Raymond James

Larry, and maybe, Brad, just on your production guidance for the year of 16 million to 16.5 million Boe basically implies your kind of fourth quarter run rate annualized gets you actually closer to the high end of the range, just kind of from a 30,000 foot view, trying to understand how you are thinking about production in terms of declines in growth and is this partly just conservatism on your part?

Brad Guidry

Part of the production is we had slowed down after the Noble acquisition. I mean we dropped down two Granite Wash rigs and we purposely and intentionally slowed things down from a capital standpoint. So, what happens is third quarter we’ve ramped up all that production builds into fourth quarter. So, fourth quarter along with Noble and our existing wells was very strong. As we get into the first quarter, the effects from slowing down in the fourth quarter show up into 2013. The other part of that is, as we add rigs throughout 2013, we’re starting out this year on a slow basis. We’re adding rigs as we go past the year, for each month you wait to add a rig essentially effects your overall production for the year. So, it’s nothing out of ordinary. I mean the declines were anticipated on our existing production and the Noble, so it’s nothing different with that. It’s more just how our program is laid out for 2013.

Jim Rollyson – Raymond James

So from a quarterly basis, it sounds like you will slip kind of slowdown in the first quarter, may be into second quarter and then start to build back up in the second half. Does that sound about accurate?

Brad Guidry

Yes, it is.

Jim Rollyson – Raymond James

Okay. Larry, on the rig side, you guys had a pretty big sequential drop-off in margins and utilization. It sounds like you’re somewhat back on track to get rigs back to work. If you’re at 68 plus, a couple more coming in, just trying to think about margins going forward. It sounds like the quarterly benefit from termination of contracts has gone almost to zero. So, if anything, that’s at least leveled out. But how are you thinking about margins going forward given the mix of everything?

Larry Pinkston

Right now, I mean, I would expect first quarter margins to be up a little bit over the fourth quarter. Of course, you always have the payroll starting over with all the taxes and stuff from the first quarter, but we had some, I don’t want to call them onetime, I mean, you seem like you have end up with having some onetime things happen three or four times.

But it was more of unusual charges coming through in the fourth quarter that right now we’re certainly not expecting them to reoccur in the first quarter. But when you get through all the other adjustments as, John, mentioned in his speech, you get through all the unusual items are – actually our direct cost and indirect cost on a per operating day basis was down in the fourth quarter versus the third quarter. So, I think we’re okay on the cost side. The revenue day rates are staying – are pretty flat. We come through the adjustment of the payoff on the contracts that we got in the third quarter. We’re not expecting any more of those of any substance in the first quarter. So, the revenue number I think is pretty firm for now.

Jim Rollyson – Raymond James

So, when you account for the payroll tax impact that always happens in 1Q you think were relatively stable in 1Q?

Larry Pinkston

Yeah, I think so. Yeah.

Jim Rollyson – Raymond James

Okay. And the last one, David, interest expense came down in a big way in the fourth quarter and basically back to like second quarter levels despite the fact that your outstanding debt is about double what it was in the second quarter. Just help me understand maybe what’s going on there and kind of how you think about interest expense for 2013?

David Merrill

Yeah. Jim, what’s primarily driving that is capitalized interest. And we have – you certainly – it’s pretty apparent that you capitalize interest on new construction projects. But the other component that impacts the E&P segment is that the capitalized interest on undeveloped leasehold that you have, so that’s – when we did the Noble acquisition that certainly increased our undeveloped acreage to some extent. And so there’s more interest expense that’s been capitalized. So, on a go forward, given our capital plans for 2013 what you see in the fourth quarter, the net relationship ought to be relatively consistent as you go into 2013.

Jim Rollyson – Raymond James

So kind of a mid 1%, kind of equivalent interest rate?

David Merrill

Right, 1% to 2%, probably, yes.

Jim Rollyson – Raymond James

Okay. Thank you. Very helpful, guys.

David Merrill

You bet. Thanks.

Larry Pinkston

Thanks, Jim.

Operator

Our next question comes from Brian Velie from Capital One. Please go ahead.

Brian Velie – Capital One

Good morning guys.

Brad Guidry

Good morning.

Larry Pinkston

Good morning.

Brian Velie – Capital One

Couple of quick questions in the Mississippian. On the initial well, you mentioned that there were two – I’m sorry, three others that are kind of waiting for connection. Can you say which counties those new wells coming on are located?

Brad Guidry

Yeah, all of the wells we drilled are in Reno County.

Brian Velie – Capital One

All in Reno, okay. And then those new wells that are still waiting there, we haven’t heard the 30-day rates yet. Are you seeing similar water cut rates as you did with the first one that you talked about today?

Brad Guidry

Yeah. We purposely didn’t talk about 30 day rate, because they’ve just not been on that long. And with the wells in an area like this, where we only had one well producing before, we’re looking at different ways of producing it. But yeah, in general, it’s all pretty similar.

Brian Velie – Capital One

Okay, great. And the only other one that I had for you, it’s the NGL pricing this quarter obviously much better than it was in 3Q. Is that a – is that due to the ethane rejection, just kind of high-grading the mix, or is there something else there?

David Merrill

No, that’s a good part of it, correct.

Brian Velie – Capital One

Okay. So, nothing really, we shouldn’t expect necessarily that NGL prices have improved that much, just...

David Merrill

No, ethane has improved from its low, but there’s still rejection going on. So, we ought to see something similar going into the first quarter of 2013.

Larry Pinkston

We’re not rejecting all ethane that we’re producing on our oil and gas sites. So, we would still have some liquids sold that will include ethane. But ethane prices are back up in the $0.24, $0.25 range and that’s a long ways back up from $0.08 and $0.15.

Brian Velie – Capital One

Right. Okay. So, finally the results that are kind of out there right now that we’re waiting on, is there any particular timeframe when we might be able to expect those from the Mississippian side of things?

Brad Guidry

Yeah. I mean now that we’ve talked about it, each quarter we’ll certainly give an update. And as we get 30-day IPs for subsequent wells, we’ll certainly disclose that.

Brian Velie – Capital One

Okay, I appreciate it. Thanks guys. That’s all we have got.

Larry Pinkston

Thanks Brian.

Operator

Our next question from Phillip Jungwirth from BMO Capital Markets. Please go ahead.

Phillip Jungwirth – BMO Capital Markets

Hey good morning guys. Just had a couple of follow-ups on the Mississippian play. The EUR range as you gave, 125 MBoe to 180 MBoe, can you tell us what the commodity mix is in that EUR assumption and then also what a first-year cumulative production would be?

Brad Guidry

The commodity mix is about 89% oil, 3% NGLs, and the remainder gas. The 30-day IP of 350 BOE per day, I don’t know – Phillip I can get you what the actual production expectation for the year is. I don’t have that right in front of me. I can tell you the forecast for the initial decline for the Mississippian is about 55% for that first year.

Phillip Jungwirth – BMO Capital Markets

Okay. But you don’t expect to see higher GORs over time then given that the oil cut is – for the EUR?

Brad Guidry

We just don’t know. The wells we’ve drilled – the subsequent wells there has been some variation in the amount of oil and gas mix. Certainly, we think this initial well is at the high end of the amount of oil from, what we’ve seen just on initial testing of some of the other wells. So we’re not really sure if that GOR will change or not. Based on – the area that we’re in up there has some vertical production, and based on that vertical production, it looks like things ought to stay pretty steady, but we just don’t know.

Phillip Jungwirth – BMO Capital Markets

And then on the well cost of $3 million, does that include the saltwater disposal infrastructure? And then how many saltwater disposal wells do you think you’ll need per producing well based on the water cut that you saw in the first well?

Brad Guidry

That cost does not include the saltwater disposal. We’ve drilled really in three different areas up there. A couple of areas already had existing facilities in there. They were an acquisition we did that included some vertical production and also had disposal wells in there. The remaining area we drilled a new well in there, and it’s servicing two wells right now. The disposal in there is down into the Arbuckle, and we think we’ll be able to service a number of wells. We don’t have that exact number at this point of the volume, but I would anticipate somewhere between 5 wells and 10 wells per saltwater disposal well.

Phillip Jungwirth – BMO Capital Markets

And then on the asset sale in Brazos and Madison County for $44 million, can you tell us how much production was associated with that? And then, when did that close?

Brad Guidry

It wasn’t a whole lot. That was an area that we acquired in an acquisition, primarily it was Buda, Georgetown horizontal, which was a fractured play. We drilled a number of horizontal Woodbine wells in that area, and the production – I don’t have it in front of me, but I suspect it was about 300 barrels of Boe equivalent, so it wasn’t a big number.

Phillip Jungwirth – BMO Capital Markets

Okay. And on the Granite Wash, the economics that you had quoted earlier in the call, did that relate primarily to your legacy Granite Wash acreage? Or is that intended to be somewhat of a mix between legacy and the newly acquired Noble acreage? And then, as you drill the Noble acreage, how do you think that would differ from your legacy acreage in terms of well costs and recoveries?

Brad Guidry

Yeah. The numbers we’re talking about, the rate of returns are from our legacy acreage. We are planning on drilling our first Granite Wash well in the Noble here at the end of this quarter. In general, Noble acreage is about 20% deeper, and we expect to get about 20% more reserves, so essentially the returns ought to be similar. But that is our expectations. When we bought Noble, that was really the model we ran in there that we had cost range from the mid 5% on – depending on how deep of wins you’re talking about drilling in the Granite Wash, but our EURs we’re expecting to be north of 4%, probably 4.5% to 5%.

Phillip Jungwirth – BMO Capital Markets

And then the last question on the E&P CapEx budget of $586 million. If I look at how much you’ve laid out by the different plays, the Wilcox, Granite Wash, Mississippian and Marmaton, in the release, I come to about $340 million. Just wondering what the delta is between the total CapEx budget and then if you sum it up by the individual plays? Is it non-op, land, just kind of what that difference would represent?

Brad Guidry

Yeah. Non-op in there – for 2012, we spent between $40 million and $50 million on non-op. So that’s a big part of it. There is additional drilling in there for our Anadarko region that’s not included as a core play, but we’ll drill some Cherokee wells and some different formations in Western Oklahoma, not a big program, but maybe five or six wells for this year. There is a couple of wells in there for the Midland area, where we have some legacy assets and basically we are responding when wells get drilled near us that appear economic, then we’ll go in and drill from that standpoint. And then tell me the rest of your question, I forgot it.

Phillip Jungwirth – BMO Capital Markets

No, that was good. Just wondering what the delta represented.

Brad Guidry

Okay.

Phillip Jungwirth – BMO Capital Markets

That’s it. That’s all I had. Thanks, guys.

Brad Guidry

Okay. Let me just add too. In land, I think for the budget this year, we have built in about $40 million, $40 million to $45 million.

Operator

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

Brad Guidry

Good morning.

Larry Pinkston

Ray.

Ray Deacon – Brean Capital

Yeah. Sorry, I was on mute. I had a follow-up on the Mississippian. Do you think that’s your kind of go-forward well cost? Or do you think you might be able to do longer laterals there? And I guess any more detail you can provide on kind of the oil and gas mix with the other wells that haven’t been on 30 days, I mean is it significantly different from the one well or kind of slightly different?

Brad Guidry

Yeah. The laterals, the last well we drilled, the one we just finished here last week, we actually drilled about 5,400 feet of lateral. So, we will be experimenting with the different lengths of laterals as we go forward. The mix that we’ve seen in the other wells, there has definitely been some variation in there. From the BTU content, we’ve been as high as 1,400. We’ve been as low as maybe 1,050. On our high end, we’re looking at gas with recoveries of NGLs up to 9 GPMs down to maybe 4 or something like that. And part of the thing is – my personal feeling is, it’s not going to vary as much as that, but it’s a little bit of a function of not having the wells online for an extended period. We have seen some variation in our initial well from where it started to where it currently is.

Ray Deacon – Brean Capital

Right.

Brad Guidry

So, that’s our expectations, but honestly we don’t have an answer. Those are all things that we’ll expect to have better answers here. And part of the reason for taking this break in drilling is to be able to answer some of those questions along with getting the pipeline in there. Until we get them selling down the pipeline for, I would say, 3 months to 6 months, we expect to see some changes in that mix.

Ray Deacon – Brean Capital

Got it, got it. Great, thank you.

Operator

(Operator Instructions) We have no further questions at this time.

Larry Pinkston

Thank you, John. Just to wrap this up, I want to thank you for joining us this morning. We will be presenting at the EnerCom Oil & Services Conference tomorrow morning in San Francisco. And we hope to see many of you there. Thank you again.

Operator

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

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