Unit Corporation (NYSE:UNT)
Q3 2010 Earnings Call
November 4, 2010 11:00 a.m. ET
Larry Pinkston - President and CEO
David Merrill - CFO
Brad Guidry - SVP, Exploration
John Cromling- EVP, Contract Drilling Operations
Bob Parks - President, Mid-Stream Segment
Brad Evans - Heartland
Good morning and welcome to Unit Corp’s Third Quarter 2010 Earnings Call. My name is Alicia and I will be facilitating the audio portion of today’s interactive broadcast. (Operator instructions)
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 could cause actual results to differ materially from those 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 the projected rate of production. Future demands for oil and natural gas; future drilling rig utilization and days 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; availability and timing of obtaining third-party services used in the drilling or completion of its oil and gas wells; anticipated oil and natural gas prices; the number of wells to be drilled by the company’s exploration segment; the 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; ability to successfully integrate recent acquisitions into the company’s operations 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.
At this time, I would now like to turn the show over to Mr. Larry Pinkston, President and Chief Executive Officer. Sir, please go ahead.
Thank you, Alicia. Welcome, everyone, this morning. We want to thank you for calling in to our third quarter conference call. I have with me today David Merrill, who is our CFO, Brad Guidry, who is the Executive Vice President of our Exploration Segment; John Cromling, who is the Executive Vice President of our Contract Drilling Operations; and Bob Parks, who is President of our Mid-Stream segment.
As we have done in the past quarters, I will spend a few minutes recapping our third quarter results, including an update of our contract drilling in our mid-stream operations. Brad then will discuss the details of our E&P operations and David will hit on a couple of key financial facts. Then we will take questions after our comments.
We released our third quarter results to the public this morning. We reported net income of $34.5 million and earnings per share of $0.73 per share. This represents a 7% increase of both net income and earnings per share over the second quarter of 2010. The increase was primarily due to 55% increase in operating profit before depreciation from our Contract Drilling segment and a 3% increase in our oil and gas segment.
Our Contract Drilling segment achieved very impressive growth in both rig utilization and daily cash flow margins during the third quarter. Rig utilization during the quarter increased by 13%, to an average of 65 rigs operating during the quarter. Rig activity continued to grow primarily with customers that are drilling oil prospects and/or high btu gas prospects in western Oklahoma and the Texas Panhandle along with the higher number of rigs working in the Bakken and Three Forks formations in North Dakota.
Demand during and subsequent to the end of the third quarter continued to show strength as evidenced by having 69 rigs operating at quarter end and 71 rigs operating today. The upgrade and refurbishment program of our drilling fleet continues to progress. We completed the upgrades on two of our rigs during the third quarter and we currently has 70 rigs in our fleet that we consider to be very competitive for horizontal drilling opportunities.
We have identified another 20 rigs primarily 800 to 1,000 horsepower rigs that are good candidates for upgrade. We will upgrade these as demand dictates. In October, we sold three of our mechanical rigs that were not good candidates for upgrading, the horizontal drilling for which we received 1,200 horsepower electric rig and $5.3 million in cash. We have now sold 11 rigs this year-to-date and we have used the proceeds from these sales to further enhance the upgrade of our rig fleet.
Currently 88% of our drilling rigs are either drilling horizontal or directional wells. Because of the demand for the 1,500 horsepower drilling rigs in the Bakken and Three Forks plays, we have now signed contracts to deliver four new rigs during 2011. The first rigs will be delivered in March of ‘11 and the other two rigs will be delivered in July. When these four rigs are delivered, we will have 14 rigs operating in this area.
Operating margins per rig per day increased significantly during the third quarter. Margins before elimination of inter-company profit were $7,100 a day per rig for the quarter, up 38% from the second quarter. Day work revenue per rig per day increased $900 per day, up 6%.
Daily operating cost per rig before elimination of inter-company costs decreased 14% to $8,900 per rig per day. We realize lower daily costs in both direct and indirect costs during the quarter. Day rates especially on the horizontal wells has continued to remain strong and they should be up another $300 to $400 in the fourth quarter.
Our mid-stream segment financial results continue to remain strong for the third quarter, even though operating profit declined from the second quarter, primarily due to lower overall liquid prices. Ethane prices in particular, bottomed out in July and have been increasing steadily since that mid-year low point.
Operating profit in the third quarter 2010, compared to the third quarter of 2009 showed an increase from 6.2 million to 6.7 million. Gathered volumes remained flat and processed volumes were up slightly compared to the second quarter of 2010. Process volumes increase mainly due to connections of new wells to our existing processing plants.
Natural gas processed volumes per day increased 2% and 8% during the third quarter of 2010 as compared to the second quarter of ‘10 and the third quarter of ‘09. Natural gas liquids sold per day decreased 7% and increased 3% for the same period comparison.
The decrease of liquids sold in the third quarter was primarily due to the reduction of ethane at our processing facilities because of the low ethane prices. We are in a start-up process at our new 50 million cubic feet per day processing plant in Hemphill County in the Texas Panhandle will be able to receive additional new volumes immediately once the plant is up and running, drilling activity in the Granite Wash continues to be strong based on the high Btu content of the gas and we anticipate possibly doubling our current process volumes of 35 million cubit feet per day over the next year.
Our Granite Wash processing capacity at the Hemphill location in the Panhandle will be approximately 100 million cubit feet per day year-end 2010. We are commencing construction of the new processing plant project in Roberts County, Texas. That is also in the Panhandle, west of our current Hemphill plant. This plant will have an initial capacity of 8 million to 10 million cubic feet per day. The plant should be constructed and operational during the second quarter of 2011. We have completed construction and begun operating a new 6 million cubic feet per day processing plant at our Osage County, Oklahoma gathering and processing site. Gas volumes available from third party producers continue to rise at this facility.
Our gas plant gathering and processing plant in Central Oklahoma has reached capacity due to a resurgence of oil and higher Btu gas drilling activity in the area. We recently purchased a 20 million a day turbo-expander skid mounted portable plant and are evaluating whether to install this skid at the Cashing plant site during 2011. Current volumes being processed are approximately 18 million cubic feet per day.
The current emphasis by the producer community on drilling for oil and high Btu gas in both conventional and unconventional resource cross events led to a substantial opportunity to evaluate and potentially develop gathering and processing prospects in the Mid-Continent and other geographical regions.
Our experience in constructing and operating gas processing plants should lead to a number of new project opportunities in the future. We are continuing to evaluate and construct facilities in Appalachian Basins on several projects.
In Centre County, Pennsylvania, progress continues. We are in final route preparations and acquisitions of right away. Multiple discussion with producers active in the area are continuing on a daily basis. In Preston County, West Virginia, we have committed to build a 16-inch pipeline and gathering agreement has been executed with a third party producer and we are finalizing the process of obtaining the required permits, performing environmental assessments and obtaining right of way prior to commencing construction. We anticipate a second quarter 2011 start-up of this project.
In our oil and gas segment, we realized a 6% increase in revenues during the third quarter to $96.6 million. The higher revenues were a result of the 7% increase in oil and natural gas equivalent production over the second quarter. Oil and natural gas production should continue to increase during the remainder of the year, as we get more closely caught up on our pending frac jobs. Just in our Granite Wash and Marmaton plays between October 1st and the end of the year, we had either completed or scheduled to complete six frac jobs in the Granite Wash play and 13 in the Marmaton play. Through the end of the third quarter, we had drilled and completed a total of 105 gross wells. We anticipate by year-end that we will complete another 55 gross wells.
Now it would be a good time for me to turn the call over to Brad, who will discuss the E&P operations.
Good morning. I will start out in the Granite Wash. During the third quarter in our operated Granite Wash play located in Roberts and Hemphill County, Texas, we completed three horizontal wells and all those wells are within the Granite Wash B zone.
The first well, the Webb A-4H which we have 83% working interest was completed in early October at a production rate of approximately 4.1 million cubic feet a day, 691 barrels of oil per day and 449 barrels of NGLs per day with 1,200 pounds of flowing casing pressure and this has an equivalent production rate of 10.9 million cubic feet a day.
The oil and gas rate on this well has been inclining over the past several weeks as the choke is opened and the barrels of the frac water decreases. The current rate is now up to 11.9 million cubic feet per day equivalent, which is the highest daily rate for any of our Granite Wash horizontal wells today.
The well has approximately 3,700 feet of lateral. It was frac'd in 11 stages of 1.2 million pounds of sand and 70,000 barrels of water. The total cost for this well is approximately $4.8 million. The second well, the Webb A-3H, which we have also 83% working interest is located in the same prospect area as the 4H. It was also completed in early October at an initial rate of 2.2 million cubic feet per day, 165 barrels oil per day, and 240 barrels of NGLs or an equivalent rate of 4.6 million cubit feet a day and completed well cost for this well was 4.5 million.
The well has approximately 2,600 feet of lateral and it was frac'd in eight stages with 973,000 pounds of sand and 47,000 barrels of water. The lower rate, we think, is attributable to a down-hole restriction which appears to be reducing the flow from the Granite Wash zone. The 3H when it was drilled looked very similar to the 4H, current plans are to drill out the packer ports in the 3H well in the next couple of weeks and we anticipate this should increase the rate more in line with what we have seen in the 4H.
The third well, the Temple A1H, which we have 48% working interest had first sales in late August. The approximate rate was 182 barrels of oil per day, 105 barrels of NGLs and 960 Mcf per day or an equivalent rate of 2.8 million cubic feet equivalent.
The lower rate in this well is attributable to a short lateral of only 2,000 feet and also a higher than usual water cut due to communication during the frac job with the water sand that is located just below the pay sand.
We have run a submersible pump in this well, which should help lift the water which should in turn increase the oil and gas production rate. The completed well cost for the Temple was $3.9 million. In addition to those three, we successfully frac’d two Granite Wash, eight sand wells in late October.
The Schaller A5h which we have a 50% working interest has a lateral length of 4,050 feet. The well was frac’d with 14 stages and 1.3 million pounds of sand and 126,000 barrels of water. The Mailer 11H which we have 100% working interest has a lateral length of 3,200 feet and it was frac’d in seven stages with 800,000 pounds of sand and 49,000 barrels of water.
The Schaller is in their early stages of the flow back after the frac and the Mailer is in the process of drilling out the ports this week prior to beginning flow back. Two additional, Granite Wash horizontals, the Webb 3H, which we have 83% working interest and the Mailer D-2H we have 100% working interest have both reached total depth in production liners and the packers have been set.
The Webb estate has a lateral length of 3,600 feet and it’s in the Granite Wash B zone and the scheduled frac on that well is late November. The Mailer D-2H which we have 100% interest has a lateral length of 3,500 feet and this is the first horizontal well that we drilled in the Granite Wash F zone. The F zone had good gas shows during the drilling of this lateral and this well is also scheduled to be frac’d in late November.
In summary, for operated Granite Wash play, we anticipate completing six Granite Wash horizontals during the fourth quarter, and this compares to only one well being completed in the first quarter only one well in the second quarter and three wells in the third quarter.
We plan to run a three to four rig horizontal drilling program in the Granite Wash in 2011 and that program should result in two to three wells coming online per month. In our non-op Granite Wash leasehold that is located in Wheeler County, Texas, two new wells were completed in the third quarter.
The Zibac 2-10H which we have a 12.5% working interest is producing approximately 7.5 million cubic feet a day and 307 barrels of oil per day. The Thomas 5H which we have approximately 13% working interest had an initial rate of 16.2 million cubic feet per day and 681 barrels of oil per day. One additional well, the Lancaster 2-58, which we have 15% working interest was also been drilled to total depth and it is waiting to be frac’d.
In our non-op Colony Wash play located in Washita County, Oklahoma the Ana number 1H, which we have a 17% working interest had first sales in late October, as well as currently flowing approximately 10.8 million cubic feet a day and 864 barrels of oil per day, with a flowing casing pressure of 4,750 pounds. We anticipate receiving several new well proposals in both of these areas in the upcoming quarters.
Moving to the Marmaton horizontal oil play in Beaver County, Oklahoma, we added a second company rig in early September and we plan to keep two rigs drilling during the fourth quarter and throughout 2011. At the end of the third quarter, we had 10 horizontal wells with an average working interest of approximately 96% that are waiting on completion, due to the unavailability of third party frac services until October of this year.
During October, we were able to successfully frac eight of those 10 wells and we have initial production rates from the first three of the wells that were frac’d. These wells had first oil sales in mid October at initial rates of 497 barrels of oil equivalent per day, 484 barrels of oil equivalent per day and 169 barrels of oil equivalent per day. Casing head gas accounts for approximately 10% of the reported well volume, which will result in additional upside with the anticipated recovery of approximately 7.5 gallons of NGLs per Mcf.
The lateral lengths of these three producing wells range from 3,800 feet to 4,000 feet and the average frac was 15 stages with approximately 800,000 pounds of sand and 40,000 barrels of water. The five other wells that were frac’d in October should have initial oil flow rates in the next couple of weeks. We have two additional frac dates scheduled in November, three frac dates in December and we are currently working to secure approximately three frac dates per month for all of 2011.
In connection with the drilling operations in the Marmaton, our staff has done an outstanding job in reducing the average drilling days from 27 days per well, when we initially began drilling this project in the late first quarter to 20 days per well at the end of the third quarter. We continue to improve the drilling process resulted in the last four wells that were drilled, were drilled on an average of 13 days, which equates to approximately 37% cost reduction of the dry hole costs or approximately $630,000 per well. With the reduced drilling days, we now anticipate we can drill our Marmaton program with two rigs instead of needing a third rig as we previously reported. Unfortunately, about approximately 50% of the cost reduction is offset by the increasing frac costs that we have seen during this year.
In our Segno play which is located in Southeast Texas, we are running two unit rigs and we have plans to continue that program throughout most of 2011. During the third quarter, we completed three new producers from various Wilcox zones. The Black Stone G number 1 which we have 100% working interest had first sales in late August. The initial rate on that well was approximately 3.5 million cubic feet per day, 120 barrels of oil per day and 250 barrels of NGLs with flowing tubing pressure of 6,600 pounds. This would be an equivalent rate of approximately 5.7 million cubic feet equivalent per day.
The Wildwood number A-3 which we also have 100% working interest was due, completed in late October from two upper Wilcox zones and the well is flowing at a combined rate of approximately 300 barrels of oil per day, 149 barrels with natural gas liquids per day and 2.1 million cubit feet or an equivalent rate of 5.5 million per day. The second well in that prospect, the Wildwood B-3, which we have 100% working interest had first sales in late October. That well was flowing at approximately 370 barrels of oil per day, 24 barrels of NGLs, and approximately 340 Mcf a day.
In addition, the BPL, which we also have 100% working interest - that well was completed during the second quarter, but it had been shut-in pending a pipeline connection since the second quarter. That well should be online in mid-November at an estimated pre frac rate of approximately 2.1 million cubic feet a day, 90 barrels of oil and 150 barrels of NGLs per day. This year is our seventh year that we have been drilling in the Segno area. This area continues to yield strong results due to the great effort by the exploration team that we have.
Moving to Shelby County, Texas, the second horizontal Haynesville well, the KC gas unit number 1H, which we have 59% working interest has drilled 4,000 feet of Haynesville lateral. That well is scheduled to be frac’d in early February of 2011. The initial Haynesville well in this prospect was the Smith 1H, it was drilled with 3,300 feet of laterals. So 700 feet less than the new well. It has been producing since late July at an initial rate of 3.6 million cubic feet a day with 5,800 pounds of flowing tubing pressure. Although earlier pipeline constraints have been resolved, we believe the operator has chosen to produce the well conservatively due to the low gas prices and the potentially enhanced ultimate recoverable gas reserves in this well. The well is currently producing 3.7 million cubic feet a day at 3200 pounds.
In Harrison County, Texas, we drilled the new Cotton Valley horizontal well out there. This well we have 33% working interest in. It went online. First sales was late September at a rate of 8.8 million cubic feet per day and 127 barrels of oil per day with 2,120 pounds of flowing tubing pressure. This well had a lateral length of 4000 feet and was fracture stimulated in 10 stages with 2.3 million pounds of sand.
An offset in this prospect is planned to begin before the year end and we also anticipate drilling a horizontal Cotton Valley well in the first quarter of 2011 on a nearby prospect that we operate.
Moving to the Bakken play, located at Williams County and McKenzie County, North Dakota. In this area, we own a non-op working interest, approximately 39,000 gross acres, 8,500 net acres. In this play, there is currently two rigs drilling and we anticipate a third rig being added in the first quarter of 2011. The recent completions during the third quarter continue to be strong oil producers with three new wells coming on during the third quarter and the early fourth quarter.
Recovich number 5-16, which we have 18% of working interest had first oil sales in mid-September, the initial rate on that well was approximately 2429 barrels of oil per day. The State 1-16 which we have a 13% working interest had initial sales in late October. The initial rate on that well was approximately 2579 barrels of oil per day. The Henderson 4-25H, which we have 10% working interest, was completed in early August at initial rate of approximately 1,313 barrels of oil per day.
Finally moving to the Marcellus shale play, which our position there is located primarily in Somerset County, Pennsylvania, where we own a 25% working interest and non-op working interest in approximately 990,000 gross acres. We are continuing to evaluate the production decline on the last horizontal well that was completed in early April 2010. The initial rate was approximately 1.5 million cubic feet per day and the well is still producing at 910 Mcf per day. This well was a short lateral of only 2600 feet.
We reported previously that we plan to drill three horizontal wells beginning in the first quarter of 2011 but now has been delayed due to the low gas environment and our shift towards plays with more oil and liquids rich components. However since the majority of these leases have 10-year term expirations, the timing delays should have a minimal impact to the overall project we have in the Marcellus.
This time, I will turn the call back over to David.
Thank you, Brad. Good morning, everyone. EBITDA for the third quarter of 2010 was $109 million, an increase of 10% from 99 million in the second quarter of 2010 and an increase of 18% from 92 million in the third quarter of 2009.
For the third quarter of 2010, the Oil and Natural Gas segment contributed 61% of EBITDA, Contract Drilling contributed 34% and Mid-Stream 5%. EBITDA for the third quarter increased from the second quarter in the Contract Drilling segment and decreased in the Oil and Natural Gas and mid-stream segments.
For the Contract Drilling segment, the increase was primarily attributable to a 13% increase in the number of drilling rigs operating, from an average drilling rig utilization of 47% in the second quarter to 54% in the third quarter, combined with a 38% increase in operating margins per rig per day before elimination of inter-company rig profit. Financial operating costs per day for the third quarter decreased $1,260 or 14% from the second quarter, of which approximately $500 per day was attributable to legal and workers' compensation items.
For the Oil and Natural Gas segment, the decrease was primarily attributable to higher operating costs and to a lesser extent lower realized commodity prices, somewhat offset by an increase in production. Operating costs per equivalent Mcf increased 6% from $1.71 to $1.82. Realized prices, including hedges for natural gas liquids and natural gas decreased 5% and 1% respectively, while prices for oil were essentially unchanged. Equivalent production increased 7%.
The unexpected shut-in of 383 million cubic feet equivalent of production due to operational issues at a third-party facility that processes our segment fuel production negatively impacted production during the third quarter. Excluding the impact of the shut-in, third quarter production would have increased 8% over the second quarter.
For the mid-stream segment, the decrease was primarily attributable to the 6% decrease in liquid sold volume somewhat offset by a 3% increase in gas process volume. DD&A for the Oil and Natural Gas segment for the third quarter increased 14% from the second quarter primarily due to increased production and an increase in the DD&A rate. DD&A rate for the third quarter was $2 per equivalent Mcf up from $1.87 per equivalent Mcf in the second quarter. Depreciation for the Contract Drilling segment for the third quarter increased 12% from the second quarter primarily due to the 13% increase in the number of drilling rigs operated. Depreciation per rig per day in the third quarter is essentially unchanged from the second quarter at $3,100 a day.
Speaking about hedging for the oil and natural gas segment, we have hedged approximately 63% of our anticipated fourth quarter natural gas production at a weighted average delivery point price of $6.29, and approximately 49% of our anticipated fourth quarter 2010 oil production at a weighted average price of $69.43. Approximately 11% of our natural gas liquids production is hedged for the fourth quarter of 2010 at a weighted average price of $41.12. In addition, we have hedged 15,000 MMBtu per day of our 2011 and 2012 natural gas production at a weighted average delivery point price of $5.42 and $5.52 respectively.
We have hedged 2,500 barrels per day of our 2011 oil production at a weighted average price of $80.32 and 1,500 barrels per day of our 2012 oil production at a weighted average price of $82.49 and have added 504 barrels per day of our 2011 natural gas liquids production at a weighted average price of $41.12. Total capital expenditures excluding acquisitions from our operating segments for the first nine months of 2010 were $344 million and for 2010, our capital expenditure budget for all three operating segments combined is $514 million excluding acquisition. The effective income tax rate for the 2010 third quarter was 38.3%, essentially unchanged from the second quarter and should approximate the rate for the year.
The percentage of tax expense to be deferred increased from the second quarter primarily due to additional depreciation allowed on new capital expenditures in 2010 and we currently estimate the deferral rate to be approximately 90%. Our debt to capitalization ratio at the end of the third quarter was 7% with 135 million of long-term debt outstanding. We have a $400 million credit facility of which we have elected to have a current commitment amount available of 325 million and our current borrowing base is 500 million as determined by our lenders in their most recent redetermination completed in September of this year. Our October working capital at the end of the third quarter was $36 million.
Alicia, we would now like to open the call for questions.
Question and Answer Session
Our first question comes from the line of Brad Evans with Heartland. Your line is open.
Brad Evans - Heartland
Fast on the draw. Good morning, guys. Hope you are doing well. I was hoping that maybe Brad could talk a little bit more about the phenomenal results on those early wells out of the Marmaton play, can you give us your thoughts in terms of pulmonary type curve in terms of expected EUR and where are AFEs running down those wells at this point?
Brad, at this point, we are still so early and we are still looking at what our pre-drill rates were, which the type curve on that was coming on at 300 barrels of oil per day. That is on average. That is what we still think will fit. We have seen it in the vertical wells there. There is a lot of variability between the wells. You may get some wells in the 700 or 800 barrels a day and some wells maybe at 100 barrels a day. So for that type curve, that setup is 300 barrels a day that equates to about 120,000 barrels of oil equivalent. At this point until we get some production history that is what we still believe is accurate. The cost in there, when we first started drilling, I was talking about the drilling days on there, that 29 drilling days equated to a dry hole cost of about 1.7 million, 1.8 million. The AFEs with this last batch we ran through is about 1.4. The actual costs we are seeing now coming in on these latest wells we have drilled for the dry hole cost is about two point, I mean, 1.2 million and then the completed well cost is up around 2.2 million to 2.4 million.
Brad Evans - Heartland
That is helpful, thank you. I am just curious; you mentioned before that the efficiencies are going to allow you to move from, take on that third rig in the play. Is there something that could cause you to maybe accelerate that play and bring that third rig in? Or I am curious what your thinking is there?
At this time, you know, we went out and looked at the acreage position we have there, the amount of rigs that would require to hold that acreage position and that is mainly the position we are looking at it right now, from a production enhancement, from a staff, if we get the staff that allows us to run the additional rigs then that would be something we would look at during next year. For right now, with getting these wells drilled in the 13 to 15 days, its turning over pretty quickly, and the land work required to stay out in front of it right now is really all we can handle at this point. That is certainly something as we go into next year we can look at.
Brad Evans - Heartland
I just have one question, on the Contract Drilling side, and I will go back in queue. Just with respect to any thoughts on fourth quarter, you know, costs on the drilling side. David, do you have any thoughts there in terms of what we should be thinking about there?
Yes, on the cost side, our actual per day costs before we eliminated inter-company cost was $8900 a day. As Larry had mentioned, it was down pretty significantly from the prior quarter all but we should there is about $200 a day of costs that were attributable to some legal and some workers' compensation items that should not be repetitive items. So our per day costs should be running around $9,400 a day. Still down from where we were in the second quarter.
We have no further questions at this time.
Well, thank you for joining us this morning. Hopefully we’ll be around to see most of you all over the next 30, 60 days. If not have a happy holiday season, and we’ll talk to you later. Thanks, bye.
This concludes today’s conference call. You may now disconnect.
Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.
THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY’S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY’S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.
If you have any additional questions about our online transcripts, please contact us at: firstname.lastname@example.org. Thank you!
THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.