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Executives

Larry Pinkston – President and CEO

Brad Guidry – SVP, Exploration

John Cromling – SVP, Drilling Operations

Bob Parks – Manager and President, Superior Pipeline Company

David Merrill – SVP, CFO and Treasurer

Analysts

Lenny Bianco – Raymond James & Associates

Cameron Horwitz – U.S. Capitol Advisors

Unit Corporation (UNT) Q3 2012 Earnings Call November 1, 2012 11:00 AM ET

Operator

Welcome to the Unit Corporation Third Quarter 2012 Earnings Conference Call. My name is Kim [ph], 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.

A number of risks and uncertainties can cause actual results to differ materially from these statements, including, the impact that any decline in wells being drilled will have on production and drilling rig utilization; the productive capabilities of the company’s wells, including the ability of recently completed wells to maintain their initial rate of production, or their projected rate of production; future demand for oil and natural gas; future drilling rig utilization and day rates; projected or anticipated 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 segments; developmental, 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 in 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 Mr. Larry Pinkston, President and CEO. Mr. Pinkston, you may begin.

Larry Pinkston

Thank you, Kim. 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 segment, after their comments, we’ll take questions.

Before we get started this morning I’d like to say that our thoughts and prayers are with those along the East coast as they begin putting their lives back together after the devastating storm this week. If we can help in any way, please just let us know.

We released third quarter results this morning. We reported net income of $46.6 million or $0.97 per share, this compares to $53.4 million or $1.11 per share for the third quarter of 2011 and adjusted net income of 52.8 million and $1.10 per share for the second quarter of 2012.

Net income for the third quarter of 2012 was down as compared to the same period in 2011 as a result of a 23% increase in natural gas prices and a 53% decrease in natural gas liquid prices.

Net income in the third quarter of 2012 was down as compared to adjusted net income in the second quarter of 2012 as a result of an $8.4 million reduction of fees associated with early termination of drilling contracts. A 4% lower regularization rate and a 34% lower price for natural gas liquids.

Our contract drilling segment, begin experiencing some softness in the rig demand in the latter part of the third quarter. The majority of this softness was with our 1,500 horsepower rigs. These rigs are utilized to drill the deeper horizontal wells. John will discuss this further with you in just a few minutes.

We were able to basically maintain our day rates for the third quarter which dropped only $139 per day. Our group did a great job of controlling daily operating cost in line of the following utilization with cost increasing only $44 per day per rig before intercompany eliminations.

Our mid-stream segment in the third quarter was impacted by lower natural gas volumes, mostly in our Texas Panhandle system. The third party processor had been offloading natural gas to ester processing because of their lack of capacity. They completed the construction of the new plant in the third quarter and reduced the volumes delivered to us.

They’re under a contract to pay a minimum amount to us through June of 2013 if they don’t deliver natural gas to us in the future periods. This segment continues to be negatively impacted by the low natural gas, liquid process as compared to 2011 and the first quarter of 2012. Bob, will have further discussion on this in a few minutes.

We have many very exciting things happened in the third quarter in our exploration production segment. We announced that we completed our purchase of oil and gas properties from Noble Energy. We’ve purchased as of the effective date of April 1st, 44 million barrels of oil equivalent reserves and 84,000 net acres in Western Oklahoma in Texas Panhandle. 80 of the 84,000 acres are held by production and 80% of the reserves are pre-develop [ph].

As of the effective date, the estimated production was 10,000 barrels of oil equivalent per day and our purchase price was 617 million. We’re very excited about the future potential of these properties because of the minimal amount of horizontal drilling on these properties. We have identified over 600 potential locations just on the 25,000 of the acres that are in the Granite Wash. The Granite Wash as you know has been one of our core areas over the last several years.

In connection with this acquisition we close on the $400 million add on to our existing public bonds in July. The sale went very smoothly and was very well received. During the quarter we also closed on the sale of two oil and natural gas property packages and receive net proceeds of 271 million. Both packages were non-core for Unit’s future plans.

We have one additional package properties located in North Dakota that we’re anticipating selling during the next six months depending on the industry conditions.

As you can tell the third quarter was a very busy, very big quarter for Unit Corporation. We believe the transactions at our [inaudible] at a very good position for significant future growth.

And now, I’d like to turn the call over to Brad, to discuss some of our exploration activities.

Brad Guidry

Good morning everyone. I’ll start out in the Marmaton. It’s located in Beaver County, Oklahoma. For the third quarter we achieved record production which results in the 26% increase over the second quarter of 2012.

Our average net daily production for the third quarter was approximately 4,000 barrels of oil equivalent, consisting of 74% of oil, 19% natural gas liquids, which has a total of 93% liquids.

For the first nine months of 2012, we had first oil and gas sales on 21 operated short lateral with the short lateral being defined as approximately 4,500 feet. And two extended laterals defined as approximately 9,500 feet.

For the short lateral well, the average working interest is 83% and the average 30-day IP rate was 332 barrels oil equivalent per day. The two long lateral wells, the average working interest was 91%, and the average 30-day IP rate was 765 barrels of oil per day.

If using the preliminary reserve estimates range for the 2012 wells in strip pricing, the short lateral wells generated rate of return ranging from 35% to 60%. In comparison, the two extended lateral wells have an average rate of return in excess of a 100%.

Based on the strong results from our initial extended lateral wells, we’re participating with other industry operators to crop legislation that would allow an extended lateral Marmaton well to be drilled across multiple pre-existing spacing units.

We are hopeful that by the end of 2013, there may be legislation in place that will allow the majority of our future Marmaton wells to be drilled as extended laterals. Until that time, we will continue to drill as many as extended lateral wells as possible using the current regulations.

We are currently drilling a third extended lateral well and we have plans to drill one in two additional extended laterals in the fourth quarter of 2012. We’re currently running two drilling rigs in this play which should result in first oil and gas sales on approximately 26 to 30 short lateral wells in four to five extended lateral wells for 2012.

We currently have leases on approximately 112,000 net acres in the play and we’re continuing to add to our lease position.

Moving to the Granite Wash located in the Texas Panhandle, we’re excited about our future drilling potential on both our newly acquired Noble leasehold and our existing leasehold.

Our plans for our overall Granite Wash play is to increase from the two rigs we’re currently running today to four rigs in January of 2013, then increased to six rigs around July of 2013.

In general, the location of the rigs will be split between the two areas. However, we will have the flexibility to move rigs to either area as needed since the majority of our leasehold is 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 Wilcox field to determine the reserves and economics of the deeper Granite Wash field base [ph] in this field.

Once we’ve establish economics, we will develop a program that will utilize pad drilling in 2014. That should both accelerate drilling and reduced well cost.

We’ve been pleased with the reduction in drilling time for a Granite Wash wells as we continue to refine our expertise and efficiencies into play. For example, the average number of days from spud to rig release for wells drilled during the first nine months of 2012 was 40 days which is a 12% reduction in drilling days as compared to our 2011 wells. This reduction translates to more wells being drilled and completed during the year.

Currently our net Granite Wash production for the third quarter averaged approximately 61 million cubic feet of gas equivalent per day consisting of about 50% liquids, this counts for about 27% of Unit’s overall production.

In the Granite Wash, we currently have a lease, we’re going approximately 48,000 net acres and we’ve identified approximately 800 potential horizontal locations on that leasehold.

Moving to the Wilcox play in Southeast Texas, we’ve previously announced the significant multi-zone deeper Wilcox field discovery which had estimated potential resource reserves 229 Bcfe gross and 159 Bcfe net with approximately 43% of the reserves [ph] consistent of the liquids.

The development of this field is continuing as planed with the completion of our fourth well during the third quarter of 2012. The well is located approximately 1 mile west of the initial discovery well and encountered an estimated 235 feet of Wilcox potential oil and gas pay spread across seven zones which confirmed our geologic interpretation for the field.

The well was completed in a single Wilcox zone at a depth of approximately 14,100 feet. After fracture stimulation, the well flowed at a rate of 5.2 million cubic feet equivalent per day and it had 8,500 pounds of flowing tubing pressure and that also is consisting of approximately 43% liquids.

The calculated absolute open flow rate for the well from the single zone is approximately 16 million cubic feet of equivalent gas per day. The fifth well in the field is currently being drilled below 13,000 feet and plans are, to drill an additional four to six wells in the field during 2013.

A long trend to the east approximately 20 miles, we have drilled two exploratory Wilcox wells that encountered several potential oil and gas pay sands. Both wells are currently being tested and the pipeline construction is in progress. We expect to have these wells following the sales by the end of this year.

In addition, we’re re-drilling [ph] several areas in our Wilcox play that could potentially be good locations to drill horizontal wells. Our current expectation is to drill our first horizontal Wilcox well in the second half of 2013.

Moving to the Mississippian located primarily in Kansas, we’re continuing to test our first horizontal well. The well was drilled to a total measure depth of 8,115 feet and includes approximately a 3,500 foot lateral. The well is place on production after fracture stimulation in May of 2012.

The current plans are to continue to test the well through the end of this year. Continue to obtain data for estimate ultimate reserves. We have drilled the second well located approximately 8 miles from the first well. The measured depth on that one was also around 8,100 feet. Lateral is about 300 feet longer for about 3,870 feet of lateral. The well is scheduled to be fracture stimulated in November of this year.

A third well is currently drilling and our current plans are to keep one rig drilling into play for the rest of 2012. Unit currently has leased approximately 100,000 net acres and we’re continuing to acquire leases in the Mississippian.

In summary, we’re excited about our future of our EMP program. We have built significant leasehold positions that continue to increase in our core areas in the Marmaton, the Granite Wash, the Wilcox and the Mississippian.

Our drilling well inventory has increased substantially. The experience and diligence of our employees has allowed us to reduce cost while increasing efficiency in all of our core areas. We continue to explore new areas that could potentially develop into new core plays for us. And we have successfully began the process of divesting of non-core assets.

The combination of all these factors and strengths along with the addition upside, we anticipate from, one, the new extended lateral drilling in our Marmaton play. Two, the recent Noble acquisition with 600 potential Granite Wash locations, three, the exploitation of our recent Wilcox field discovery and the potential for horizontal drilling in the Wilcox, and finally, four, the development of our new Mississippian play, all these factors together should create a great opportunity for sustainable growth for Unit for the years to come.

I’ll now turn the call over to John.

John Cromling

Thank you, Brad. Our contract drilling segment experienced a challenging third quarter with rig activity decreasing during the latter part of the quarter as it is throughout the industry.

Day rates decreased slightly during the third quarter. Various day rate for the third quarter was $19,989 as compared to $20,128 for the second quarter.

The average per day operating margin for the third quarter, before elimination of inter-company profits was $9,672 which is a $1,459 per day or a 13% decrease over the second quarter.

The largest factor in this decrease in average margins is due to the differences in early termination fees. During the second quarter, these fees equated to $2,188 per day. During the third quarter they average $1,007 per day for a reduction of $1,181 per day.

The daily operating expenses were almost constant during the quarter. However, revenues were down due to a slight decrease in day rates and less standby income.

Our average rig utilization during the third quarter was 73.4 rigs which is 4% less than the second quarter. We continued to experience decrease in demand for the 1,500 horse power rigs. But they’ve been able to offset this somewhat with additional 700 to 1,000 horse power rigs being employed.

The interest in activity continues to increase in the Mississippian play, in Northern Oklahoma and Kansas. We recently added four additional rigs to this area. All of these rigs have been refurbished in preparation for this work.

It is our expectation that the increased activity in this market will allow us to add additional rigs of this size during the remainder of the year.

Since many operators have decreased their activity in order to stay within their budgets, we do not expect the activity level to increase much during the fourth quarter as compared to our current level.

However, we do expect a gradual increase during the first quarter of 2013. And this should include adding larger rigs going back into service.

We still think outlook for the drilling company is good. And we’ll continue to refurbish rigs and be prepared for that.

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

Bob Parks

Thank you, John. The mid-stream segment continues to be very active in several key producing areas. While we are continuing to produce record high volumes since the start of the facilities, liquids prices continued to be at low levels resulting in lower operating profit.

Our segment operating profit decreased 4% for the second quarter of 2012 and decreased 10% from the third quarter of 2011. Both gas and liquids prices were lower in the third quarter compared to the third quarter of last year.

Gas prices average $4 in the third quarter of 2011 and declined to an average price of $2.66 in the third quarter of 2012, representing a 34% decline.

Liquid prices were also lower by approximately 36% from the third quarter of 2011 compared to the third quarter of 2012. While all the liquid components experienced a decline, ethane prices fell still dramatically from an average of $0.47 a gallon in the third quarter of 2011 to an average of $0.15 a gallon of the third quarter of 2012.

The 68% decline was significantly affected our processing margin since ethane represent the largest liquid component recovered at our facilities. In addition to these factors we also engaged ethane rejection during much of the quarter which further impacted our margins.

As mentioned previously by Larry, in addition to lower prices during the third quarter of 2012, we had a third party processor after completion of their own processing facility discontinue delivery of gas to our Hemphill facility.

Even though, we no longer receive their gas, we were still being paid the demand fee until the end of the contract term which is mid-2013. This event impacted our third quarter operating profit volumes to the extent we’re only receiving the demand fee and not additional upgrades from processing the gas.

Now, I will discuss areas of significant activity for the mid-stream segment. In the Mississippian play in North Central Oklahoma, we continue to be active and remained the key area focus for the mid-stream segment.

We have completed the initial phase of our new Bellmon gathering system which is located in Noble and Kay counties in Oklahoma. This facility includes the 10 million cubic foot per day rental processing plant which we are planning to upgrade to an owned 30 million cubic foot per day turbo expanded plant in the first quarter of 2013.

During the course of the third quarter, we had four different pipeline construction projects underway in the Mississippian play, totaling approximately 80 miles of pipe. Each of these pipeline projects is expected to be completed during the fourth quarter.

Turning to the Appalachian region, we’re continuing to increase our presence in the Marcellus shale play. We’ve completed two pipeline projects in this area that are focused on dry gas areas.

Even though our focus has been on dry gas, we are continuing to expand our gathering systems to keep up with third party drilling activities. During the third quarter, we began the installation of 7 miles of pipeline in our Pittsburg mill system. That will extend our system North to the next well pad the third party producer is completing.

From this well pad, we anticipate connecting four new wells in the fourth quarter of 2012 bringing the total wells connected to the systems 10 [ph]. The producer has plans to maintain a steady drilling schedule for the rest of this year and end of 2013.

In summary, we are maintaining our focus on key producing areas and are continuing to complete projects which will position us well for future success as we continue to expand our mid-stream business.

I’ll now turn the call over to David.

David Merrill

Thanks Bob. As Larry, previously mentioned, all within the third quarter of 2012, we announced and closed the Noble acquisition, the divestiture of certain of our Bakken in South Texas properties, a private offering of 400 million of senior subordinated notes and the amendment of our credit facility.

We ended the third quarter of 2012 with total long-term debt of approximately $650 million, consisting solely of senior subordinated notes and nothing drawn on our credit facility, giving us the debt to capitalization ratio of 24%.

Our current borrowing base associated with the credit facility is $800 million, as determined by our lenders in their most recent redetermination completed in October, and we had elected an available commitment amount of $500,000.

Prior to October 1st of 2012, we designated most of our commodity derivative contracts as cash flow hedges whose unrealized fair value gains and losses were recorded to accumulated other comprehensive income on the balance sheet.

However, we have decided that starting October 1, 2012, any new hedges will not be designated as cash flow hedges, therefore the change in fair value for all perspective commodity hedges will be reflected in the income statement.

This change will not, as mentioned, apply to any contracts that were entered into before October 1st of 2012, and they will remain designated as cash flow hedges throughout their contract term.

Effective income tax rate for the first nine months of 2012 was 39.1%, and we currently estimate the rate for the year to be approximately the same.

The current portion of income taxes is estimated to be between 2% and 3% for the year. We anticipate our operating segment capital expenditures for 2012 excluding acquisitions, to be approximately $733 million.

We are in the early stages of developing our capital expenditures budget for 2013, but currently expect it to be relatively close to anticipated cash flows for 2013.

Kim, we would now like to open the call for questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) And at this time, we have a question from Lenny Bianco, from Raymond James. Please go ahead.

Lenny Bianco – Raymond James & Associates

Good morning, guys, congrats on the strong quarter.

Larry Pinkston

Thanks, Lenny.

Lenny Bianco – Raymond James & Associates

Starting on the drilling business, three long term contracts cancelled during the quarter, are you getting indications from additional customers that there could be more coming down the pike, or has that kind of stabilized?

Larry Pinkston

We’ve not heard of any other long term contracts thus far, Lenny.

Lenny Bianco – Raymond James & Associates

Great. And on those cancellations, do you get a sense that it’s more customer-specific or is it, I know you alluded to the 1500 horsepower class rig being weak. Is it that class? Or maybe a little color around the ones that were cancelled.

Larry Pinkston

We’ve had four cancelled in the Bakken, in total, and that’s been because of results from their drilling program. Of course everything is indirectly related to pricing but it was not a direct relationship to the pricing, it was just, they were about satisfied with the results or the reserves they were getting in the area they were drilling in.

Lenny Bianco – Raymond James & Associates

Okay and kind of looking at the contracts that are slated to roll off in the next couple of quarters, as you start discussions to re-sign those, are you having to give up some term or some rate to get them committed or kind of give us a little color on that front if you can.

John Cromling

Lenny, this is John. There’s really been very little discussions at this point because it’s still three or four months out before most of those happen. A lot of things can change between now and then, of course, good or bad.

Typically, if you’re in a market that’s going down, you’re going to have to give up some right, and most likely give up some term. But we have not gotten to that point yet.

In fact we have already seen indications of things of interest picking back up in areas in the Bakken. So we’re optimistic as [ph] we’ll be better than worse.

Lenny Bianco – Raymond James & Associates

Great. And maybe shifting gears one quick one on the EMP side and I’ll turn it back. Are you guys comfortable with the current 2013 hedging position you have? Or you’re kind of looking to add incremental hedges as we close out the year here?

Larry Pinkston

We’re pretty comfortable right now. I mean we’re continually watching it, but gas prices should pop up some more from where they are now, we might do a little bit more on gas, but we’re feeling better on the gas side with the rig cut coming down as drastically as it has in the oil side, you get back up and that $95 plus range which we’ll probably look at a little bit more and then start looking at 2014 before long.

But before you leave, let me add on the drilling side, almost across the board with our customers base, what we’re hearing from them is, they’re basically out of budget for this year. And most of them, majority of them, if not most of them are saying that after the first year, they’re planning on getting active again, and we’ve heard that before, we’ve actually had one customer sign contracts with their rigs back to work in January.

So I think there is a truth to that, I mean it’s certainly true in our EMP division, we just got wells, we got wells drilled faster this year than we were expecting to getting them drilled. And we cut back on our rig count the fourth quarter because of the budget reasons.

So I think there is some upside there from the beginning of the year, if what we’re hearing from our customer base is active, of course, a lot can happen between now and January and February also.

Lenny Bianco – Raymond James & Associates

Thanks. I appreciate the additional color. And I’d say that’s probably what we’ve been hearing a lot of through this earning cycle at least that next year might be taken up based on budgetary constraints in the last half of this part of this year.

So thanks again and I’ll turn it back.

Operator

Thank you. Our next question comes from Cameron Horwitz from U.S. Capitol Advisors. Please go ahead.

Cameron Horwitz – U.S. Capitol Advisors

Hey guys, good morning.

John Cromling

Good morning.

Larry Pinkston

Good morning.

Cameron Horwitz – U.S. Capitol Advisors

Hey, question for Brad. On the Marmaton long lateral, there’s a couple of questions I guess, how far apart were those two wells?

Brad Guidry

About 2500 feet. They were essentially within the same, if you take two sections stacked on top of each other, they were both within that section, one in the east half, one in the west half.

Cameron Horwitz – U.S. Capitol Advisors

Okay. And then just on the 30-day rates, were both those right around the average or I guess, can you just separate those two out?

Brad Guidry

The first well was 960, the second well was 570. So it was a little bit off.

Cameron Horwitz – U.S. Capitol Advisors

Okay. And on that first one, it’s been on for a while now, do you have the current rate on that?

Brad Guidry

Current rate is probably equivalent somewhere on 250 barrels equivalent.

Cameron Horwitz – U.S. Capitol Advisors

Okay. Okay, that’s helpful. And then jumping over to the missed [ph] play, I know you guys aren’t talking much yet there, but you are adding acreage here, up to 100,000 acres, pretty material, it seems like you’re seeing something there that’s given you some positive inclination I guess without talking about rates. Can you just kind of give us an idea of what you’re seeing that gives us, gives you some encouragement there?

Brad Guidry

Yes, I mean the well has been on since mid May. We’re getting ready to run an extended bottom hole build up in there. What we’re really trying to do is get a better feel of what the ultimate reserves are.

These wells that you artificially lift [ph], it just takes a lot more time to get through, to get them pumped down to let’s see what happens the decline after you get them pumped down, look at the pressure. So we’re moving ahead with drilling out there, the big question is the ultimate economics and we obviously think it’s going to work we just don’t know to what magnitude yet.

Cameron Horwitz – U.S. Capitol Advisors

Okay, so we’ll probably hear about that in early ‘13.

Brad Guidry

Yes.

Cameron Horwitz – U.S. Capitol Advisors

Okay. And just in terms of what you think cost there, what are you seeing on the waiting [ph] edge, are you seeing that go up?

Brad Guidry

It’s definitely increased from – we’ve been building a position out there, probably over the last 12 to 18 months and it certainly gone up.

A lot of the lease hole in our area is not available anymore, so you’re not seeing a lot of leases being taken in the specific areas that we’re in.

But it’s definitely doubled, maybe tripled in price, but it started off from a pretty low base. I think all in cost in there from what we’ve got leased, is somewhere $300 to $400.

Cameron Horwitz – U.S. Capitol Advisors

Okay. Thank you for that. And then there’s one other quick question here on the drilling business. I know you guys have your core operating areas, Anadarko, Rocky in the Gulf Coast, but are you doing any contemplation of expanding those, take advantages in some of these other opportunities, I guess maybe the [inaudible] or Utica, or just some of these other areas. Any thoughts there?

Brad Guidry

Sure, I mean we’re always looking art those areas. And right set of circumstances, we definitely look, reason to different areas, you don’t want to move one rig into a new area, you really need a base to build from these areas.

Sometimes they have a tendency to come and go pretty quickly. But no, we’re always looking at that.

Cameron Horwitz – U.S. Capitol Advisors

Okay. Thanks a lot guys, I appreciate the color.

Brad Guidry

Thanks, Cameron.

Operator

Thank you. (Operator instructions) And at this time, I show no further questions. I’ll now turn the call back to Mr. Pinkston for closing remarks.

Larry Pinkston

Thank you, Kim. We certainly want to thank you for joining us this morning. And we hope to see many of you over the next few weeks. 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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