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 23, 2010
UNIT CORPORATION REPORTS 2009 FOURTH QUARTER & YEAR-END RESULTS

Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) announced today net income of $28.5 million, or $0.60 per diluted share, for the three months ended December 31, 2009, compared to a net loss of $119.8 million, or $2.57 per diluted share, for the three months ended December 31, 2008.  Included in the fourth quarter 2008 results was a non-cash ceiling test write down of $282.0 million ($175.5 million after tax, or $3.76 per diluted share).  The ceiling test write down was required to reduce the carrying value of the company’s oil and natural gas properties due to significantly lower commodity prices existing at year-end 2008.  Excluding the effect of the ceiling test write down, net income for the fourth quarter of 2008 would have been $55.7 million, or $1.19 per diluted share (see Non-GAAP Financial Measures below).  Total revenues for the fourth quarter of 2009 were $177.3 million (27% contract drilling, 51% oil and natural gas, and 21% mid-stream).  For the fourth quarter of 2008 total revenues were $291.0 million (53% contract drilling, 37% oil and natural gas, and 10% mid-stream).

For all of 2009, Unit reported a net loss of $55.5 million, or $1.18 per diluted share, compared to 2008 net income of $143.6 million, or $3.06 per diluted share.  Included in the 2009 results is a previously reported $281.2 million ($175.1 million after tax, or $3.70 per diluted share) non-cash ceiling test write down that occurred in the first quarter.  Excluding the effect of the ceiling test write down, net income for 2009 would have been $119.6 million, or $2.52 per diluted share (see Non-GAAP Financial Measures below).   Excluding the effect of the fourth quarter 2008 ceiling test write down discussed above, net income for 2008 would have been $319.1 million, or $6.80 per diluted share (see Non-GAAP Financial Measures below).  Total revenues for all of 2009 were $709.9 million (33% contract drilling, 50% oil and natural gas, and 15% mid-stream), compared to $1,358.1 million (46% contract drilling, 41% oil and natural gas, and 13% mid-stream) for all of 2008.


CONTRACT DRILLING SEGMENT INFORMATION
Average drilling rig utilization for the fourth quarter of 2009 was 36.7 drilling rigs, or 28%, a decrease of 62% from the fourth quarter of 2008, and an increase of 6% from the third quarter of 2009.  Contract drilling rig rates for the fourth quarter of 2009 averaged $14,708 per day, a decrease of 24%, or $4,622 per day, from the fourth quarter of 2008, and a decrease of 4%, or $652 per day, from the third quarter of 2009.  Average operating margins for the fourth quarter of 2009 were $5,268 per day (before elimination of intercompany drilling rig profit and bad debt expense of $0.4 million; see Non-GAAP Financial Measures below) as compared to $9,525 per day (before elimination of intercompany drilling rig profit and bad debt expense of $7.9 million; see Non-GAAP Financial Measures below) for the same quarter in 2008, a decrease of 45%.  Approximately $619 per day of the fourth quarter 2009 average operating margin was the result of early termination fees associated with the cancellation of long-term contracts.

    For the year ended December 31, 2009, drilling rig utilization averaged 30%, or 38.9 drilling rigs, as compared to 79%, or 103.1 drilling rigs, during 2008, a decrease of 62%.  2009 average operating margins were $6,894 per day (before elimination of intercompany drilling rig profit and bad debt expense of $1.5 million; see Non-GAAP Financial Measures below) as compared to $8,987 per day (before elimination of intercompany drilling rig profit and bad debt expense of $29.4 million for 2008; see Non-GAAP Financial Measures below), a decrease of 23%.  Approximately $428 per day of the 2009 average operating margin was the result of early termination fees associated with the cancellation of long-term contracts.

Currently, Unit has 128 drilling rigs of which 62 are under contract for work.  Contracts with terms ranging from six months to two years in length are in place for 26 of the 62 drilling rigs under contract for work.  Of the 128 drilling rigs, five are subject to purchase and sales agreements to be sold to an unaffiliated third party over the next six months.  None of the 62 drilling rigs that are under work contracts is included in the drilling rigs to be sold.  The following table illustrates this segment’s drilling rig count at the end of each period and its average utilization rate during the period:
 
1
 
   4th Qtr 09   3rd Qtr 09
2nd Qtr 09
1st Qtr 09
4th Qtr 08
3rd Qtr 08
2nd Qtr 08
1st Qtr 08
4th Qtr 07
Rigs
130   130
131
131
132
131
131
129
129
Utilization
 28% 26% 
24%
40%
74%
85%
80%
78%
80%
 
            Larry Pinkston, Unit's Chief Executive Officer and President, said:  “Dayrates continued to be negatively impacted by low commodity prices and the expiration of long-term contracts.  We have, however, experienced an increase in the demand for our drilling rigs and are receiving increases in dayrates on rigs focused on horizontal drilling activity.  Recently, we announced the sale of eight of our idle mechanical drilling rigs to an unaffiliated third party.  These rigs range in horsepower from 800 to 1,000.  The closing of the sale of three of these rigs occurred this month bringing our total rig fleet to 128.  Three more are scheduled to close during the remaining part of the first quarter of 2010 with the last transaction for the remaining two rigs anticipated to close during the second quarter of 2010.  Total proceeds from the sale of all of these drilling rigs will be $23.9 million, resulting in an estimated gain of $6.1 million.  The proceeds will be used to refurbish and upgrade certain rigs in our existing fleet that we intend to target toward horizontal drilling activity.  We recently placed into service in our Rocky Mountain division a 1,500 horsepower, diesel-electric drilling rig that previously had been placed on hold during 2009 by our customer.  At the completion of the sale of the rigs and with the additional rig recently placed into service, our drilling rig fleet will total 123.”

OIL AND NATURAL GAS SEGMENT INFORMATION
·  
Completed 95 gross wells during 2009 with a success rate of 94%.
·  
Approximately 63% of anticipated natural gas production and 59% of anticipated crude oil production is hedged for 2010.
·  
Plan to participate in the drilling of 175 wells during 2010 with preliminary production guidance of 66.0 to 67.0 Bcfe.
 
Fourth quarter 2009 production was 295,000 barrels of oil, in comparison to 318,000 barrels of oil in the fourth quarter of 2008, a 7% decrease.  Natural gas liquids (NGLs) production during the fourth quarter of 2009 was 346,000 barrels in comparison to 427,000 barrels in the fourth quarter of 2008, a 19% decrease.  Fourth quarter 2009 natural gas production decreased 15% to 10.5 billion cubic feet (Bcf) from 12.3 Bcf during the comparable quarter of 2008.  Fourth quarter 2009 equivalent production totaled 14.3 Bcfe, a 15% decrease over the fourth quarter 2008.  Total production for 2009 was 60.7 Bcfe, a decrease of 4% over the 63.4 Bcfe produced during 2008.
 

Unit’s average natural gas price for the fourth quarter of 2009 increased 4% to $5.77 per thousand cubic feet (Mcf) as compared to $5.55 per Mcf for the fourth quarter of 2008.  Unit’s average oil price for the fourth quarter of 2009 was $61.57 per barrel compared to $77.71 per barrel for the fourth quarter of 2008, a 21% decrease, and Unit’s average NGLs price for the fourth quarter of 2009 was $26.02 per barrel compared to $26.17 per barrel for the fourth quarter of 2008, a 1% decrease.  For 2009, Unit’s average natural gas price decreased 27% to $5.59 per Mcf as compared to $7.62 per Mcf for 2008.  Unit’s average oil price for 2009 was $56.33 per barrel compared to $93.87 per barrel during 2008, a 40% decrease.  Unit’s average NGLs price for 2009 was $22.81 per barrel compared to $47.42 per barrel during 2008, a 52% decrease.

    For 2010, approximately 63% of the company’s anticipated average daily natural gas production is hedged and 59% of its anticipated daily oil production is hedged.  The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $6.95.  The average basis differentials for the swaps are ($0.66).  Of the oil hedges, 60% are under swap contracts at an average price of $61.36 and 40% are under a collar contract with a floor of $67.50 and a ceiling of $81.53.

            The following table illustrates this segment’s production and certain results for the periods indicated:
 
  4th Qtr 09 3rd Qtr 09
2nd Qtr 09
1st Qtr 09
4th Qtr 08
3rd Qtr 08
2nd Qtr 08
1st Qtr 08
4th Qtr 07
Production, Bcfe
 14.3  14.7
15.4
16.3
16.8
15.9
16.0
14.7
14.7
Realized Price, Mcfe
 $6.12  $5.92
$5.75
$5.48
$6.21
$9.49
$10.19
$8.72
$7.66
Wells Drilled (gross)
 37  21
16
21
67
82
72
57
81
Success Rate
 92%  90%
100%
90%
90%
89%
90%
86%
90%

(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
 
 
2
 
During 2009, Unit participated in the drilling of 95 wells, of which 89 were completed as producing wells for a success rate of 94% in comparison to the completion of 278 wells with an 88% success rate during 2008.

Unit’s exploration and production segment plans to increase activity in several of its core and emerging operating areas.  In the Granite Wash play, located in the Texas Panhandle and western Oklahoma, the company owns approximately 95,000 gross and 38,000 net acres.  During 2009 we drilled and operated 13 vertical wells and one horizontal well in the Texas Panhandle.  The vertical wells had an average working interest of 66% and estimated gross reserves of 1.8 Bcfe per well at an average gross completed well cost of $2.3 million.  We have a 70% working interest in the horizontal well which averaged 4.2 MMcf per day of natural gas, 500 barrels of oil per day and 600 barrels of NGLs per day, or 10.8 MMcfe per day, over the initial 30 day flow period beginning in late December 2009.  The well was drilled with a 4,000’ lateral that was fracture stimulated in 11 stages utilizing approximately 48,000 barrels of water and 1,000,000 pounds of sand.  Estimated ultimate gross reserves are 6.0 to 8.0 Bcfe at an approximate gross completed well cost of $3.8 million.  We drilled our first horizontal Granite Wash well in late 2008 which had a 2,400’ lateral and was fracture stimulated in six stages utilizing 16,000 barrels of water and 500,000 pounds of sand.  The highest 30 day flow rate achieved from the well was 5.5 MMcfe per day and the well is currently producing 1.8 MMcfe per day.  For 2010, the company plans to participate in approximately 9 gross (4 net) vertical wells and 31 gross (14 net) horizontal wells at a total net cost to the company of approximately $70 million.  The Segno Wilcox play, located in Polk, Tyler and Hardin Counties, Texas, continues to grow.  During 2009, we completed eight wells with an average working interest of 86% at a 75% success rate.  The average gross completed well cost was $2.7 million per well with estimated gross reserves of approximately 3.0 Bcfe per well.  The Wing #3 (100% working interest) was drilled in the fourth quarter of 2009 and has been selling an average of 5.5 MMcfe per day of natural gas and 125 barrels of oil per day, or 6.3 MMcfe per day, over a 31 day period beginning in late December 2009.  We estimate reserves on this well between 15.0 to 20.0 Bcfe.  We have expanded our Segno prospect area to the south by entering into a joint exploration agreement with an undisclosed third party for the use of a proprietary 3-D seismic survey covering approximately 151 square miles.  By drilling and operating certain wells, we will earn an interest in (i) the wells, (ii) oil and gas leases covering approximately 29,000 gross acres and (iii) a license to the 3-D data.  For 2010, Unit plans to drill 23 gross (17.5 net) wells at an approximate net cost of $48 million.  In the Haynesville Shale play of East Texas, Unit owns 16,204 gross acres and 11,302 net acres in Shelby County and 20,000 gross and 8,700 net acres in Harrison County.  During 2010, the company plans to participate in five horizontal wells and two vertical wells at an approximate total net cost to the company of $31 million.  In the Marcellus Shale play, Unit owns 197,000 gross and 49,500 net acres, mainly in Somerset County, Pennsylvania.  During 2009, Unit participated in three vertical wells and two horizontal wells at a total net cost of $7.3 million.  One horizontal well is in the early stages of flowing back after fracture stimulation and the second horizontal well is scheduled to be fracture stimulated in the second quarter of 2010.  Any wells drilled in 2010 will be determined pending the results of the two horizontal wells.

Pinkston said:  “Our exploration and production segment had a challenging year in 2009.  We reduced our drilling activity substantially during the first half of the year while commodity prices were decreasing.  During the second half of the year, this segment began to increase its drilling activity as the cost to drill wells became more economical.  We recently announced our total proved reserves at December 31, 2009 were 577.0 Bcfe of natural gas, a 1% increase over our 2008 total proved reserves.  On a debt-adjusted per share basis, December 31, 2009 total proved reserves increased 10% over 2008 total proved reserves.  New SEC rules for measuring reserves, including the method of determining year-end prices, primarily contributed to the negative revisions to our reserves of 38 Bcfe.  Our production replacement for 2009 was 175%, excluding the negative revisions, or 113% when those revisions are taken into account.  During 2010, we plan to participate in the drilling of 175 wells, an 84% increase over 2009.  Our preliminary annual production guidance for 2010 is approximately 66.0 to 67.0 Bcfe, an increase of 9% to 10% over 2009.”


 
MID-STREAM SEGMENT INFORMATION
 
·  
Increased 2009 processing volumes per day and liquids sold volumes per day by 12% and 24%, respectively.
·  
37 new wells connected to existing systems during 2009.

Fourth quarter of 2009 processing volumes of 77,501 MMBtu per day and liquids sold volumes of 263,668 gallons per day increased 7% and 34%, respectively, over the fourth quarter of 2008.  Fourth quarter 2009 gathering volumes were 177,145 MMBtu per day, a 6% decrease over fourth quarter of 2008.  Operating profit (as defined in the Selected Financial and Operational Highlights) for the fourth quarter was $9.0 million, an increase of $2.8 million from the third quarter of 2009, due primarily to increased liquids prices and increases in liquids sold and processed volumes, which resulted in increased processing margins.

For 2009, processing volumes of 75,908 MMBtu per day and liquids sold volumes of 243,492 gallons per day increased 12% and 24%, respectively, from 2008.  Gathering volumes for 2009 were 183,989 MMBtu per day, a 7% decrease from 2008.
 
 
3
 
The following table illustrates certain results from this segment’s operations for the periods indicated:
 
 4th Qtr 09  3rd Qtr 09
2nd Qtr 09
1st Qtr 09
4th Qtr 08
3rd Qtr 08
2nd Qtr 08
1st Qtr 08
4th Qtr 07
Gas gathered
MMBtu/day
 177,145  179,047
187,666
192,320
187,585
195,914
205,397
200,697
212,786
Gas processed
MMBtu/day
 77,501  77,923
75,481
72,650
72,491
71,260
67,545
59,797
59,009
Liquids sold
Gallons/day
 263,668  251,830
239,121
218,762
197,428
199,805
202,130
183,924
169,897

 
    Unit’s mid-stream segment operates three natural gas treatment plants, owns eight processing plants, 33 active gathering systems and 839 miles of pipeline.

    Pinkston said:  “During 2009, our mid-stream segment connected 37 new wells to existing systems and added an additional 69 miles of pipeline.  We are pleased with the volume growth and results that this segment has been able to achieve during a year of reduced drilling activity by exploration and production companies.  We are optimistic about the growth opportunities of our mid-stream operations, despite the weak economy.”


FINANCIAL INFORMATION
Unit ended the year with long-term debt of $30.0 million and a debt to capitalization ratio of 2%.  Under the company’s credit facility, the amount available to be borrowed is the lesser of the amount elected by the company as the commitment amount (currently $325 million) or the value of the borrowing base as determined by the lenders under the credit facility, but not to exceed the maximum credit facility amount of $400 million.  As of October 1, 2009, Unit’s borrowing base was reaffirmed by its lenders at $475 million.  The company recently increased its 2010 capital expenditures budget for all its business segments to $494 million from $467, as previously announced.  The $27 million increase is for its contract drilling segment, primarily associated with using the proceeds from the sale of the previously mentioned drilling rigs to accelerate the refurbishment and upgrading of existing rigs in its fleet targeted toward horizontal drilling activities.


MANAGEMENT COMMENT
    Larry Pinkston said: “We are pleased with our 2009 fourth quarter and year end results.  2009 was a challenging year as the weak economy continued to persist.  Our long-term debt at the end of the year was $30.0 million, $169.5 million less than at year end 2008.  The reduction in our debt was primarily funded from lower capital spending relative to our cash flow, supported by a strong commodity hedge position, along with proceeds from the sale of certain Appalachia acreage and related collection of third party costs.  An increase in demand for drilling activity by exploration and production companies has materialized during the fourth quarter and we are optimistic about what 2010 holds for Unit.  We believe that we are well positioned to take advantage of any growth opportunities that prove economic to the company.”


WEBCAST
Unit will webcast its fourth quarter and year end earnings conference call live over the Internet on February 23, 2010 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 twelve months.
 


_____________________________________________________
 
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.
 
 
4
 
    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 the 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 oil and natural gas segment, development, operational, implementation and opportunity risks, 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.
 
 
5
 
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,
 
 
2009
 
2008
 
2009
 
2008
 
Statement of Income:
                       
Revenues:
                       
Contract drilling
$
47,932
 
$
155,208
 
$
236,315
 
$
622,727
 
Oil and natural gas
 
90,480
   
107,354
   
357,879
   
553,998
 
Gas gathering and processing
 
37,024
   
28,628
   
108,628
   
181,730
 
Other
 
1,896
   
(169
 
7,076
   
(362
Total revenues
 
177,332
   
291,021
   
709,898
   
1,358,093
 
                         
Expenses:
                       
Contract drilling:
                       
Operating costs
 
30,515
   
78,366
   
140,080
   
312,907
 
Depreciation
 
11,523
   
18,521
   
45,326
   
69,841
 
Oil and natural gas:
                       
Operating costs
 
24,888
   
25,886
   
87,734
   
116,239
 
Depreciation, depletion
                       
and amortization
 
24,881
   
44,794
   
114,681
   
159,550
 
        Impairment of oil and natural
            gas properties
 
 
---
   
 
281,966
   
 
281,241
   
 
281,966
 
Gas gathering and processing:
                       
Operating costs
 
28,020
   
24,849
   
87,908
   
150,466
 
Depreciation
                       
    and amortization
 
3,938
   
3,890
   
16,104
   
14,822
 
General and administrative
 
6,923
   
5,240
   
24,011
   
25,419
 
Interest, net
 
---
   
142
   
539
   
1,304
 
Total expenses
 
130,688
   
483,654
   
797,624
   
1,132,514
 
Income (Loss) Before Income Taxes
 
46,644
   
(192,633)
   
(87,726
 
225,579
 
                         
Income Tax Expense (Benefit):
                       
Current
 
(10,041
 
(284
 
(223
 
40,877
 
Deferred
 
28,172
   
(72,501
 
(32,003
 
41,077
 
Total income taxes
 
18,131
   
(72,785
 
(32,226
 
81,954
 
                         
Net Income (Loss)
$
28,513
 
$
(119,848
$
(55,500
$
143,625
 
                         
Net Income (Loss) per
   Common Share:
                       
Basic
$
0.61
 
$
(2.57
$
(1.18
)
$
3.08
 
Diluted
$
0.60
 
$
(2.57
$
(1.18
$
3.06
 
Weighted Average Common
                       
Shares Outstanding:
                       
Basic
 
47,020
   
46,639
   
46,990
   
46,586
 
Diluted
 
47,503
   
46,639
   
46,990
   
46,909
 
 
 
6
 
   
 December 31,
     
 December 31,
   
   
 2009
     
 2008
   
 Balance Sheet Data:
                   
 Current assets
 
$
128,095
     
 $
286,585
   
 Total assets
 
$
2,228,399
     
 $
2,581,866
   
 Current liabilities
 
$
105,147
     
 $
196,399
   
 Long-term debt
 
$
30,000
     
 $
199,500
   
 Other long-term liabilities
 
$
81,126
     
 $
75,807
   
 Deferred income taxes
 
$
446,316
     
 $
477,061
   
 Shareholders’ equity
 
$
1,565,810
     
 $
1,633,099
   

   
Twelve Months Ended December 31,
 
   
 2009
     
2008
 
Statement of Cash Flows Data:
                 
Cash Flow From Operations before Changes
                 
 in Operating Assets and Liabilities (1)
 
$
380,762
     
$
730,336
 
Net Change in Operating Assets and Liabilities
   
109,713
       
(40,423
)
Net Cash Provided by Operating Activities
 
$
490,475
     
$
689,913
 
Net Cash Used in Investing Activities
 
$
(271,927
)
   
$
 (806,141
)
Net Cash Provided by (Used in) Financing
    Activities
 
 
$
(217,992
)
   
 
$
115,736
 


 
Three Months Ended
 
Twelve Months Ended
 
 
December 31,
 
December 31,
 
 
2009
 
2008
 
2009
 
2008
 
Contract Drilling Operations Data:
                       
Rigs Utilized
 
36.7
   
96.7
   
38.9
   
103.1
 
Operating Margins (2)
 
36%
   
50%
   
41%
   
50%
 
Operating Profit Before Depreciation (2) ($MM)
    $
            17.4
 
    $
            76.8
 
    $
            96.2
 
   $
          309.8
 
                         
Oil and Natural Gas Operations Data:
                       
Production:
                       
Oil – MBbls
 
295
   
318
   
1,286
   
1,261
 
Natural Gas Liquids - MBbls
 
346
   
427
   
1,488
   
1,388
 
Natural Gas - MMcf
 
10,489
   
12,331
   
44,063
   
47,473
 
Average Prices:
                       
Oil price per barrel received
Oil price per barrel received, excluding hedges
$
$
61.57
73.02
 
$
$
77.71
56.20
 
$
$
56.33
56.64
 
$
$
93.87
98.02
 
NGLs price per barrel received
NGLs price per barrel received,
   excluding hedges
$
 
$
26.02
 
36.10
 
$
 
$
26.17
 
26.17
 
$
 
$
22.81
 
25.66
 
$
 
$
47.42
 
47.38
 
Natural Gas price per Mcf received
Natural Gas price per Mcf received,
   excluding hedges
$
 
$
5.77
 
3.90
 
$
 
$
5.55
 
4.54
 
$
 
$
5.59
 
3.26
 
$
 
$
7.62
 
7.53
 
Operating Profit Before DD&A and
                       
 impairment (2) ($MM)
$
65.6
 
$
81.5
 
$
270.1
 
$
437.8
 
                         
Gas Gathering and Processing Operations Data:
                       
Gas Gathering - MMBtu/day
 
177,145
   
187,585
   
183,989
   
197,367
 
Gas Processing - MMBtu/day
 
77,501
   
72,491
   
75,908
   
67,796
 
Liquids Sold – Gallons/day
 
263,668
   
197,428
   
243,492
   
195,837
 
Operating Profit Before Depreciation
                       
    and Amortization (2) ($MM)
$
9.0
 
$
3.8
 
$
20.7
 
$
31.3
 
__________
(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 and impairment, general and administrative and interest expense. Operating margins are calculated by dividing operating profit by segment revenue.
7
 
 
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 net income excluding the effect of the impairment of our oil and natural gas properties, earnings per share excluding the effect of the impairment of our oil and natural gas properties, cash flow from operations before changes in working capital and our drilling segment’s average daily operating margin before elimination of drilling rig profit.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2009 and 2008. 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 Net Income and Earnings per Share
 Excluding the Effect of Impairment of Oil and Natural Gas Properties


   
Three Months Ended
   
Twelve Months Ended
 
   
December 31,
   
December 31,
 
     
2009
   
2008
   
2009
   
2008
 
   
(In thousands)
 
Net income including effect of impairment of oil
  and natural gas properties:
                         
    Net income (loss)
 
$
28,513
 
$
(119,848
$
(55,500
$
143,625
 
    Add:
                         
        Impairment of oil and natural gas properties
                         
          (net of income tax)
   
  ---
   
175,524
   
175,072
   
175,524
 
    Net income excluding effect of impairment of
       oil and natural gas properties
 
$
28,513
 
$
55,676
 
$
119,572
 
$
319,149
 
                           
Diluted earnings per share including effect of
                         
  impairment of oil and natural gas properties:
                         
    Diluted earnings per share
    Add:
        Diluted earnings per share from impairment
 
$
0.60
 
$
(2.57
$
(1.18
)
$
3.06
 
          of oil and natural gas properties
   
---
   
3.76
   
3.70
   
3.74
 
    Diluted earnings per share excluding effect of
                         
      impairment of oil and natural gas properties
 
$
0.60
 
$
1.19
 
$
2.52
 
$
6.80
 
 ________________ 
 

We have included the net income excluding the effect of impairment of oil and natural gas properties and diluted earnings per share excluding the effect of impairment of oil and natural gas properties because:
·  
We use the adjusted net income to evaluate the operational performance of the company.
·  
The adjusted net income is more comparable to earnings estimates provided by securities analyst.
·  
The impairment of oil and natural gas properties does not occur on a recurring basis and the amount and timing of impairments cannot be reasonably estimated for budgeting purposes and is therefore typically not included for forecasting operating results.
 
 
8
 
 





Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities

 
 
   
Twelve Months Ended
December 31,
       
     
2009
   
2008
       
   
(In thousands)
         
    Net cash provided by operating activities
 
$
490,475
 
$
689,913
       
    Subtract:
                   
        Net change in operating assets and liabilities
   
(109,713
 
40,423
       
    Cash flow from operations before changes
                   
      in operating assets and liabilities
 
$
380,762
 
$
730,336
       
 ________________ 

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 Rig Profit

   
Three Months Ended
   
Twelve Months Ended
 
   
December 31,
   
December 31,
 
     
2009
   
2008
   
2009
   
2008
 
     
                                 (In thousands)
    Contract drilling revenue
 
$
47,932
 
$
155,208
 
$
236,315
 
$
622,727
 
    Contract drilling operating cost
   
30,515
   
78,366
   
140,080
   
312,907
 
       Operating profit from contract drilling
   
17,417
   
76,842
   
96,235
   
309,820
 
    Add:
    Elimination of intercompany rig profit
       and bad debt expense
   
377
   
7,922
   
1,549
   
29,381
 
    Operating profit from contract drilling
                         
       before elimination of intercompany
                         
       rig profit
   
17,794
   
84,764
   
97,784
   
339,201
 
    Contract drilling operating days
   
3,378
   
8,899
   
14,183
   
37,745
 
    Average daily operating margin before
                         
       elimination of rig profit
 
$
5,268
 
$
9,525
 
$
6,894
 
$
8,987
 
 ________________ 

We have included the average daily operating margin before elimination of rig profit because:
·  
Our management uses the measurement to evaluate the cash flow performance or 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.

9

The following information was filed by Unit Corp (UNT) on Tuesday, February 23, 2010 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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