News
UNIT CORPORATION
 
7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136
 
Telephone 918 493-7700, Fax 918 493-7714

 
Contact:
David T. Merrill
 
Chief Financial Officer
 
and Treasurer
 
(918) 493-7700
www.unitcorp.com
 
For Immediate Release…
February 21, 2012
 

UNIT CORPORATION REPORTS 2011 FOURTH QUARTER AND YEAR END RESULTS


 
        Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) reported net income of $51.7 million, or $1.08 per diluted share, for the three months ended December 31, 2011.  For the same period in 2010, net income was $43.7 million, or $0.92 per diluted share.  Total revenues for the fourth quarter of 2011 were $345.6 million (41% contract drilling, 41% oil and natural gas, and 18% mid-stream), compared to $252.6 million (39% contract drilling, 45% oil and natural gas, and 16% mid-stream) for the fourth quarter of 2010.

        For all of 2011, Unit reported net income of $195.9 million, or $4.08 per diluted share.  For the same period in 2010, net income was $146.5 million, or $3.09 per diluted share.  Total revenues for all of 2011 were $1,208.4 million (40% contract drilling, 43% oil and natural gas, and 17% mid-stream), compared to $881.8 million (36% contract drilling, 45% oil and natural gas, and 18% mid-stream) for the same period in 2010.


CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the fourth quarter of 2011 was 82.1, an increase of 16% from the fourth quarter of 2010, and an increase of 4% from the third quarter of 2011.  Per day drilling rig rates for the fourth quarter of 2011 averaged $19,330, an increase of 17%, or $2,760, from the fourth quarter of 2010, and essentially unchanged from the third quarter of 2011.  Average per day operating margin for the fourth quarter of 2011 was $9,037 (before elimination of intercompany drilling rig profit and bad debt expense of $4.9 million). This compares to $7,559 (before elimination of intercompany drilling rig profit of $4.4 million) for the fourth quarter of 2010, an increase of 20% or $1,478.  As compared to the third quarter of 2011 ($8,413 before elimination of intercompany drilling rig profit of $4.8 million) fourth quarter 2011 operating margin increased 7% (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below).

For all of 2011, Unit averaged 76.1 drilling rigs working, an increase of 24% from 61.4 drilling rigs working during 2010.  Average per day operating margin for all of 2011 was $8,496 (before elimination of intercompany drilling rig profit and bad debt expense of $19.9 million) as compared to $6,202 (before elimination of intercompany drilling rig profit of $9.2 million) for all of 2010, an increase of 37% (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below).
 
 
1
 
        The following table illustrates Unit’s drilling rig count at the end of each period and average utilization rate during the period:

 
   4th Qtr 11 3rd Qtr 11 2nd Qtr 11 1st Qtr 11  4th Qtr 10  3rd Qtr 10 2nd Qtr 10 1st Qtr 10   4th Qtr 09
Rigs
 127  126  123  122  121  123 123  125  130
Utilization
 65%  63%  60%  58%  59%  54%  47%  40% 28%
 
Larry Pinkston, Unit's Chief Executive Officer and President, said:  “We are pleased with the results that our contract drilling segment has been able to obtain.  The fourth quarter of 2011 was the seventh consecutive quarter of increased per day operating margins.  As the industry has continued to transition to drilling horizontal or directional wells, we have been able to respond to that demand by refurbishing our existing drilling rigs or adding new drilling rigs.  Approximately 93% of our drilling rigs working today are drilling for oil or natural gas liquids (NGLs) and approximately 98% are drilling horizontal or directional wells.  We recently entered into an agreement to build a new 1,500 horsepower, diesel-electric drilling rig to be used in North Dakota.  The drilling rig will be under a three-year contract and should be completed during the second quarter of 2012.  After year-end, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third party.  On completion of the new drilling rig, we will have 128 drilling rigs in our fleet.  Currently, 83 of our drilling rigs are under contract.  Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 60 of those 83 drilling rigs.  Of these contracts, 9 are up for renewal during the first quarter of 2012, 12 during the second quarter of 2012, 16 during the third quarter of 2012, seven during the fourth quarter of 2012, and 16 in 2013 and beyond.  These contracts do not include the term contract for the new drilling rig.”


OIL AND NATURAL GAS SEGMENT INFORMATION
·  
During 2011, Unit’s oil and NGLs reserves increased 16% and 37%, respectively.
·  
Replaced 202% of 2011 production with new reserve additions, of which 141% was through the drill bit.
·  
Total production for 2011 was 12.1 MMBoe, an increase of 23% over 2010, and included an increase in oil and NGLs production of 55%.
·  
Production guidance for 2012 is 13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011.

Fourth quarter 2011 oil production was 744,000 barrels, as compared to 519,000 barrels for the same period of 2010, an increase of 43%.  Natural gas liquids (NGLs) production during the fourth quarter of 2011 was 616,000 barrels, an increase of 52% when compared to 406,000 barrels for the same period of 2010.  Fourth quarter 2011 natural gas production increased 7% to 11.4 billion cubic feet (Bcf) compared to 10.6 Bcf for the comparable quarter of 2010.  Fourth quarter 2011 equivalent production averaged 35.4 MBoe per day, an increase of 21% over the fourth quarter of 2010 and an increase of 4% over the third quarter of 2011.  Total production for 2011 was 12.1 MMBoe, an increase of 23% over the 9.9 MMBoe produced during 2010.
 
        Unit’s average natural gas price, including the effects of hedges, for the fourth quarter of 2011 decreased 24% to $4.09 per thousand cubic feet (Mcf) as compared to $5.39 per Mcf for the fourth quarter of 2010.  Unit’s average oil price, including the effects of hedges, for the fourth quarter of 2011 was $88.06 per barrel compared to $74.28 per barrel for the fourth quarter of 2010, an increase of 19%, and Unit’s average NGLs price, including the effects of hedges, for the fourth quarter of 2011 was $43.47 per barrel compared to $40.16 per barrel for the fourth quarter of 2010, an increase of 8%.
 
        For 2011, Unit’s average natural gas price, including the effects of hedges, decreased 24% to $4.26 per Mcf as compared to $5.62 per Mcf for 2010.  Unit’s average oil price, including the effects of hedges, for 2011 was $87.18 per barrel compared to $69.52 per barrel for 2010, a 25% increase.  Unit’s average NGLs price, including the effects of hedges, for 2011 was $43.64 per barrel compared to $37.04 per barrel during 2010, an 18% increase.

For 2012, Unit has hedged approximately 50,000 MMBtu per day of its natural gas production and approximately 6,100 Bbls per day of its oil production.  Unit has also hedged 1,966 Bbls per day of its first quarter NGLs production, 926 Bbls per day of its second quarter NGLs production, 380 Bbls per day of its third quarter NGLs production and 380 Bbls per day of its fourth quarter NGLs production. The natural gas production is hedged under swap contracts at an average price of $5.01 per MMBtu.  The oil production is hedged under swap contracts at an average price of $97.55 per barrel. The NGLs production is hedged under swap contracts at an average price of $42.53 per barrel for the first quarter, $41.15 per barrel for the second quarter, $51.28 per barrel for the third quarter and $50.28 per barrel for the fourth quarter.

        For 2013, Unit has hedged 3,000 Bbls per day of its oil production.  The oil production is hedged under swap contracts at an average price of $101.91 per barrel.      
           
 
2
 
        The following table illustrates certain results for the periods indicated:
 
   4th Qtr 11 3rd Qtr 11 2nd Qtr 11  1st Qtr 11 4th Qtr 10 3rd Qtr 10  2nd Qtr 10 1st Qtr 10  4th Qtr 09 
Oil and NGL Production, MBo   1,359.9  1,197.5 1,158.6 1,034.0   925.5 756.5  708.6  679.4 641.0
Natural Gas Production, Bcf  11.4  11.6  10.9  10.2  10.6  10.4  9.7  10.0  10.5
Production, MBoe
 3,255  3,123  2,983  2,739 2,698  2,478  2,325 2,352  2,389
Production, MBoe/day  35.4  33.9  32.8  30.4 29.3 27.0 25.6  26.1  26.0
Realized Price, Boe (1)
 $42.65  $41.75 $42.23  $40.00  $41.58  $38.16  $38.22  $40.92  $36.72
 
(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
 
        Pinkston said:  “We are pleased with the results from our exploration operations.  The fourth quarter marks the eighth consecutive quarter that liquids (oil and NGLs) production has increased.  Our strategy of drilling oil or NGLs rich wells is evident in our 2011 production results.  Liquids production represented 42% and 34% of total equivalent production and 67% and 49% of this segment’s revenues during the fourth quarter of 2011 and 2010, respectively.  Total equivalent production increased 23% to 12.1 MMBoe over 2010, while our total liquids production for 2011 increased 55% over 2010.  Our total proved oil and natural gas reserves at December 31, 2011 were 116.0 MMBoe, a 12% increase over our 2010 total proved reserves.  The reserve growth consisted of a 16% and 37% increase in oil and NGLs, respectively, while natural gas reserves increased 5%.  Our production replacement for 2011 was 202%, with 141% through the drill bit.  Our preliminary annual production guidance for 2012 is approximately 13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011.”
 

MID-STREAM SEGMENT INFORMATION
 
·  
Increased 2011 liquids sold per day volumes, processing volumes per day, and gathering volumes per day by 52%, 41% and 17%, respectively, over 2010.
·  
Completed construction of 16-mile, 16” pipeline and related compressor station in Preston County, West Virginia.  The system is currently flowing 6 MMcf per day.
·  
Due to high level of activity around the Hemphill facility in Texas, a 45 MMcf per day gas processing plant will be installed with completion anticipated during second quarter of 2012.
 
        Fourth quarter of 2011 per day processing volumes were 156,721 MMBtu while liquids sold volumes were 511,410 gallons per day, an increase of 84% and 76%, respectively, over the fourth quarter of 2010.  Fourth quarter 2011 per day gathering volumes were 257,398 MMBtu, an increase of 37% over the fourth quarter of 2010.  Operating profit (as defined in the Selected Financial and Operational Highlights) for the fourth quarter was $7.7 million, a decrease of 22% from the fourth quarter of 2010, due primarily to renegotiated contracts with customers at one of our processing plants whereby the contracts changed from percent of index to percent of proceeds.  Compared to the third quarter of 2011, operating profit increased 4% primarily due to increased volumes.
 
        For 2011, processing volumes of 116,161 MMBtu per day and liquids sold volumes of 412,064 gallons per day increased 41% and 52%, respectively, over 2010.  Gathering volumes for 2011 were 215,805 MMBtu per day, a 17% increase over 2010.
          
        The following table illustrates certain results from this segment’s operations for the periods indicated:
 
   4th Qtr 11  3rd Qtr 11  2nd Qtr 11  1st Qtr 11 4th Qtr 10   3rd Qtr 10  2nd Qtr 10  1st Qtr 10 4th Qtr 09 
Gas gathered
MMBtu/day
 257,398  228,247  190,921  185,730  188,252  183,161  183,858 180,117  177,145 
Gas processed
MMBtu/day
 156,721  129,820  90,737  86,445  85,195  84,175  82,699 76,513   77,501
Liquids sold
Gallons/day
 511,410  449,604  356,484  328,333  291,186  260,519  279,736  253,707  263,668
 
 
3
 
Pinkston said:  “With the demand we are seeing in the industry for additional mid-stream infrastructure, we should continue to experience exciting growth opportunities for this segment.”


FINANCIAL INFORMATION
        Unit ended the year with working capital of $15.7 million, long-term debt of $300.0 million ($250 million of senior subordinated notes and $50.0 million under its senior credit agreement), and a debt to capitalization ratio of 13%.  Under its credit agreement, the amount available for Unit to borrow is the lesser of the amount Unit elects as the commitment amount (currently $250 million) or the value of the borrowing base as determined by the lenders (currently $600 million), but in either event not to exceed the maximum credit facility amount of $750 million.


MANAGEMENT COMMENT
Pinkston said: “We are pleased with our 2011 fourth quarter and the positive momentum each of our business segments carries into 2012.  While we plan for growth in all three of our business segments, we are monitoring the potential impacts that current low natural gas prices may have on our operations as well as our customers.  In response to these current natural gas prices, we may act to curtail up to 20 MMcf per day, or 16%, of our current daily natural gas production, or 9% of our total equivalent production.  Any curtailment could result in subsequent changes to our 2012 preliminary production guidance, depending on the amount of the curtailment and how long we elect to curtail our production.  Changing commodity prices, including any reductions in current oil and NGLs prices, may also result in modifications to our 2012 capital expenditures budget; however, decisions on any changes are not anticipated until after the first quarter of 2012.  As we monitor natural gas prices, we will remain focused on the opportunities each of our business segments have for high-return projects.  We will continue to focus our exploration operations on oil and natural gas liquids rich plays like the Granite Wash and Marmaton formations.  Our contract drilling operations will continue to refurbish and upgrade certain drilling rigs while adding new rigs to our fleet as we respond to the demand for horizontal drilling by exploration and production companies.  Our mid-stream segment will continue to grow with new pipeline projects, the expansion of existing facilities and developing additional opportunities in various basins throughout the country.”


WEBCAST
        Unit will webcast its fourth quarter and year end earnings conference call live over the Internet on February 21, 2012 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to www.unitcorp.com at least fifteen minutes prior to the start of the call to download and install any necessary audio software. For those who are not available to listen to the live webcast, a replay will be available shortly after the call and will remain on the site for 90 days.



_____________________________________________________
 


Unit Corporation is a Tulsa-based, publicly held energy company engaged through its subsidiaries in oil and gas exploration, production, contract drilling and gas gathering and processing. Unit’s Common Stock is listed on the New York Stock Exchange   under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.

This news release 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 release 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 these statements, including the impact that the current decline in wells being drilled will have on production and drilling rig utilization, productive capabilities of the Company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected growth of the Company’s oil and natural gas production, oil and gas reserve information, as well as its ability to meet its 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 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.

 
4
Unit Corporation
Selected Financial and Operations Highlights
(In thousands except per share and operations data)

 
Three Months Ended
 
Twelve Months Ended
 
 
December 31,
 
December 31,
 
 
2011
 
2010
 
2011
 
2010
 
                 
Statement of Operations:
                       
Revenues:
                       
Contract drilling
$
142,553
 
$
98,465
 
$
484,651
 
$
316,384
 
Oil and natural gas
 
139,923
   
114,056
   
516,316
   
400,807
 
Gas gathering and processing
 
63,418
   
39,608
   
208,238
   
154,516
 
Other, net
 
(268
 
447
   
(834
 
10,138
 
                         
Total revenues
 
345,626
   
252,576
   
1,208,371
   
881,845
 
                         
                         
Expenses:
                       
Contract drilling:
                       
Operating costs
 
79,813
   
53,966
   
269,899
   
186,813
 
Depreciation
 
22,334
   
21,270
   
79,667
   
69,970
 
Oil and natural gas:
                       
Operating costs
 
37,475
   
29,422
   
131,271
   
105,365
 
Depreciation, depletion
                       
and amortization
 
51,337
   
37,047
   
183,350
   
118,793
 
Gas gathering and processing:
                       
Operating costs
 
55,716
   
29,739
   
174,859
   
122,146
 
Depreciation
                       
    and amortization
 
4,474
   
3,639
   
16,101
   
15,385
 
General and administrative
 
7,867
   
6,780
   
30,055
   
26,152
 
Interest, net
 
2,089
   
---
   
4,167
   
---
 
                         
Total expenses
 
261,105
   
181,863
   
889,369
   
644,624
 
Income Before Income Taxes
 
84,521
   
70,713
   
319,002
   
237,221
 
                         
                         
Income Tax Expense (Benefit):
                       
Current
 
1,533
   
(7,447
 
(2,416
 
(9,935
Deferred
 
31,327
   
34,495
   
125,551
   
100,672
 
                         
Total income taxes
 
32,860
   
27,048
   
123,135
   
90,737
 
                         
                         
Net Income
$
51,661
 
$
43,665
 
$
195,867
 
$
146,484
 
                         
                         
Net Income per Common Share:
                       
Basic
$
1.08
 
$
0.92
 
$
4.11
 
$
3.10
 
Diluted
$
1.08
 
$
0.92
 
$
4.08
 
$
3.09
 
                         
Weighted Average Common
                       
Shares Outstanding:
                       
Basic
 
47,703
   
47,457
   
47,658
   
47,278
 
Diluted
 
48,028
   
47,678
   
47,951
   
47,454
 
 
 
5
 
   
 December 31,
     
 December 31,
 
   
 2011
     
 2010
 
 Balance Sheet Data:
                 
 Current assets
 
$
228,465
     
 $
188,180
 
 Total assets
 
$
3,256,720
     
 $
2,669,240
 
 Current liabilities
 
$
212,750
     
 $
147,128
 
 Long-term debt
 
$
300,000
     
 $
163,000
 
 Other long-term liabilities
 
$
113,830
     
 $
92,389
 
 Deferred income taxes
 
$
683,123
     
 $
556,106
 
 Shareholders’ equity
 
$
1,947,017
     
 $
1,710,617
 
 
   
Twelve Months Ended December 31,
 
           
 2011
         
2010
 
Statement of Cash Flows Data:
                 
Cash Flow From Operations before Changes
                 
 in Operating Assets and Liabilities (1)
 
$
618,746
     
$
454,492
 
Net Change in Operating Assets and Liabilities
   
(10,291
)
     
(64,420
)
Net Cash Provided by Operating Activities
 
$
608,455
     
$
390,072
 
Net Cash Used in Investing Activities
 
$
(768,236
)
   
$
 (536,261
)
Net Cash Provided by
     Financing Activities
 
 
$
159,257
     
 
$
146,408
 
 
 
Three Months Ended
 
Twelve Months Ended
 
 
December 31,
 
December 31,
 
 
2011
 
2010
 
2011
 
2010
 
Contract Drilling Operations Data:
                       
Rigs Utilized
 
82.1
   
70.9
   
76.1
   
61.4
 
Operating Margins (2)
 
44%
   
45%
   
44%
   
41%
 
Operating Profit Before Depreciation (2) ($MM)
    $
            62.7
 
    $
            44.4
 
    $
          214.8
 
   $ 
          129.6
 
                         
Oil and Natural Gas Operations Data:
                       
Production:
                       
Oil – MBbls
 
744
   
519
   
2,511
   
1,521
 
Natural Gas Liquids - MBbls
 
616
   
406
   
2,239
   
1,549
 
Natural Gas - MMcf
 
11,374
   
10,635
   
44,104
   
40,756
 
Average Prices:
                       
Oil price per barrel received
Oil price per barrel received, excluding hedges
$
$
88.06
92.88
 
$
$
74.28
81.56
 
$
$
87.18
93.49
 
$
$
69.52
76.65
 
NGLs price per barrel received
NGLs price per barrel received,
   excluding hedges
$
 
$
43.47
 
          43.85
 
$
 
$
40.16
 
40.59
 
$
 
$
43.64
 
44.44
 
$
 
$
37.04
 
36.96
 
Natural Gas price per Mcf received
Natural Gas price per Mcf received,
   excluding hedges
$
 
$
4.09
 
            3.29
 
$
 
$
5.39
 
3.41
 
$
 
$
4.26
 
3.78
 
$
 
$
5.62
 
4.05
 
Operating Profit Before DD&A (2) ($MM)
 $
         102.4
 
$
84.6
 
$
385.0
 
$
295.4
 
                         
Mid-Stream Operations Data:
                       
Gas Gathering - MMBtu/day
 
257,398
   
188,252
   
215,805
   
183,867
 
Gas Processing - MMBtu/day
 
156,721
   
85,195
   
116,161
   
82,175
 
Liquids Sold – Gallons/day
 
511,410
   
291,186
   
412,064
   
271,360
 
Operating Profit Before Depreciation
                       
    and Amortization (2) ($MM)
$
7.7
 
$
9.9
 
$
33.4
 
$
32.4
 
_____________
(1) The company considers its cash flow from operations before changes in operating assets and liabilities an important measure in meeting the performance goals of the company (see Non-GAAP Financial Measures below).
(2) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization general and administrative and interest expense. Operating margins are calculated by dividing operating profit by segment revenue.
 
6
Non-GAAP Financial Measures
 
We report our financial results in accordance with generally accepted account principles (“GAAP”). We believe certain non-GAAP performance measures provide users of our financial information and our management additional meaningful information to evaluate the performance of our company.

This press release includes cash flow from operations before changes in operating assets and liabilities and our drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2011 and 2010. Non-GAAP financial measures should not be considered by themselves or a substitute for our results reported in accordance with GAAP.

Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
 
   
Twelve Months Ended
December 31,
 
     
2011
   
2010
 
   
(In thousands)
   
    Net cash provided by operating activities
 
$
608,455
 
$
390,072
 
    Subtract:
             
        Net change in operating assets and liabilities
   
10,291
   
64,420
 
    Cash flow from operations before changes
             
      in operating assets and liabilities
 
$
618,746
 
$
454,492
 
               
 ________________ 
We have included the cash flow from operations before changes in operating assets and liabilities because:
·  
It is an accepted financial indicator used by our management and companies in our industry to measure the company’s ability to generate cash which is used to internally fund our business activities.
·  
It is used by investors and financial analysts to evaluate the performance of our company.
 
Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense

 
Three Months Ended
 
Twelve Months Ended
 
September 30,
 
December 31,
 
December 31,
 
2011
 
 2011
 
 2010
 
 2011
 
2010
 
 
(In thousands)
Contract drilling revenue
$
128,927
 
$
142,553
 
$
98,465
 
$
484,651
 
$
316,384
 
Contract drilling operating cost
 
73,004
   
79,813
   
53,966
   
269,899
   
186,813
 
    Operating profit from contract drilling
 
55,923
   
62,740
   
44,499
   
214,752
   
129,571
 
Add:
Elimination of intercompany rig profit
    and bad debt expense
 
4,820
   
 
 
 4,945
   
4,440
   
19,900
   
9,158
 
Operating profit from contract drilling
                             
    before elimination of intercompany
                             
      rig profit and bad debt expense
 
60,743
   
67,685
   
48,939
   
234,652
   
138,729
 
Contract drilling operating days
 
7,220
   
7,490
   
6,474
   
27,619
   
22,367
 
Average daily operating margin before
                             
    elimination of intercompany rig profit
      and bad debt expense
$
8,413
 
$
9,037
 
$
7,559
 
$
8,496
 
$
6,202
 
                               
 ________________ 
We have included the average daily operating margin before elimination of intercompany rig profit and bad debt expense because:
·  
Our management uses the measurement to evaluate the cash flow performance of our contract drilling segment and to evaluate the performance of contract drilling management.
·  
It is used by investors and financial analysts to evaluate the performance of our company.
 
7

The following information was filed by Unit Corp (UNT) on Tuesday, February 21, 2012 as an 8K 2.02 statement, which is an earnings press release pertaining to results of operations and financial condition. It may be helpful to assess the quality of management by comparing the information in the press release to the information in the accompanying 10-K Annual Report statement of earnings and operation as management may choose to highlight particular information in the press release.

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