Unit Corporation Reports 2012 Third Quarter and First Nine Months Results

  Unit Corporation Reports 2012 Third Quarter and First Nine Months Results

Business Wire

TULSA, Okla. -- November 01, 2012

Unit Corporation (NYSE: UNT) reported net income of $46.6 million, or $0.97
per diluted share, for the three months ended September 30, 2012, compared to
net income of $53.4 million, or $1.11 per diluted share for the third quarter
of 2011. Total revenues for the third quarter of 2012 were $317.8 million (42%
contract drilling, 41% oil and natural gas, and 17% mid-stream), compared to
$323.8 million (39% contract drilling, 42% oil and natural gas, and 19%
mid-stream) for the third quarter of 2011.

For the first nine months of 2012, Unit reported net income of $79.7 million,
or $1.66 per diluted share. For the same period in 2011, net income was $144.2
million, or $3.01 per diluted share. Included in the second quarter 2012
results was a non-cash ceiling test write down of $115.9 million ($72.1
million after tax, or $1.50 per diluted share). The ceiling test write down
was required to reduce the carrying value of the company’s oil and natural gas
properties resulting from significantly lower commodity prices during the
second quarter of 2012. Excluding the ceiling test write down, net income for
the nine months of 2012 would have been $151.9 million, or $3.16 per diluted
share, a 5% increase over the first nine months of 2011 (see Non-GAAP
Financial Measures below). Total revenues for the first nine months of 2012
were $980.1 million (43% contract drilling, 41% oil and natural gas, and 16%
mid-stream), compared to $862.7 million (39% contract drilling, 44% oil and
natural gas, and 17% mid-stream) for the first nine months of 2011.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the third quarter of 2012 was
73.4, a decrease of 7% from the third quarter of 2011, and a decrease of 4%
from the second quarter of 2012. Per day drilling rig rates for the third
quarter of 2012 averaged $19,989, an increase of 4%, or $680, from the third
quarter of 2011, and a 1% decrease, or $139, from the second quarter of 2012.
Average per day operating margin for the third quarter of 2012 was $9,672
(before elimination of intercompany drilling rig profit of $4.0 million). This
compares to $8,413 (before elimination of intercompany drilling rig profit of
$4.8 million) for the third quarter of 2011, an increase of 15%, or $1,259. As
compared to the second quarter of 2012 ($11,130 before elimination of
intercompany drilling rig profit of $4.7 million), third quarter 2012
operating margin decreased 13% or $1,458 (in each case with regard to the
elimination of intercompany drilling rig profit see Non-GAAP Financial
Measures below). Approximately $1,007 and $2,188 per day of the third quarter
2012 and second quarter 2012 average operating margin, respectively, was the
result of early termination fees resulting from the cancellation of certain
long-term contracts.

For the first nine months of 2012, Unit averaged 77.2 drilling rigs working,
an increase of 4% from 74.0 drilling rigs working during the first nine months
of 2011. Average per day operating margin for the first nine months of 2012
was $10,063 (before elimination of intercompany drilling rig profit of $12.9
million) as compared to $8,295 (before elimination of intercompany drilling
rig profit of $15.0 million) for the first nine months of 2011, an increase of
21% (in each case with regard to the elimination of intercompany drilling rig
profit see Non-GAAP Financial Measures below). Approximately $1,077 per day of
the first nine months of 2012 average operating margin was the result of early
termination fees resulting from the cancellation of certain long-term
contracts.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “Industry
demand for drilling rigs has softened during the second half of the year as
operators are reducing their drilling efforts in order to stay within their
2012 budgets. We believe that after the first of the year, drilling activity
should improve as operators start over with their new budgets for 2013.
Approximately 98% of our drilling rigs working today are drilling for oil or
natural gas liquids (NGLs). Currently, we have 127 drilling rigs in our fleet,
of which 63 are under contract. Long-term contracts (contracts with original
terms ranging from six months to two years in length) are in place for 32 of
those 63 drilling rigs. Of these contracts, 11 are up for renewal during the
fourth quarter of 2012, and 21 in 2013 and beyond. During the quarter, we had
three drilling rigs that were under long-term contracts that were terminated
early by the operator. The early termination fees associated with those
contracts were approximately $6.7 million.”

The following table illustrates Unit’s drilling rig count at the end of each
period and average utilization rate during the period:

              3^rd    2^nd    1^st    4^th    3^rd   2^nd   1^st   4^th   3^rd
            Qtr    Qtr    Qtr    Qtr    Qtr   Qtr   Qtr   Qtr   Qtr
              12      12      12      11      11     11     11     10     10
Rigs         127    128    127    127    126   123   122   121   123
Utilization  58%    60%    64%    65%    63%   60%   58%   59%   54%
                                                                

OIL AND NATURAL GAS SEGMENT INFORMATION

  *Third quarter 2012 production was 3.5 MMBoe, an increase of 12% over the
    third quarter 2011.
  *44% of third quarter 2012 production was oil and NGLs compared to 38% for
    the third quarter of 2011.
  *Production guidance for 2012, including the impact of acquisitions, is
    13.9 to 14.2 MMBoe, an increase of 15% to 17% over 2011.

The third quarter marks the 11th consecutive quarter that liquids (oil and
NGLs) production has increased. Unit’s strategy of drilling oil or NGLs rich
wells is evident in its production results. Liquids production represented 44%
of total equivalent production during both the third and second quarters of
2012. Third quarter 2012 total equivalent production increased 12% over the
third quarter of 2011 to 3.5 MMBoe, while total liquids production for the
third quarter of 2012 increased 29% over the comparable quarter of 2011.
Liquids production for the third quarter of 2012 has increased 110% since the
first quarter of 2009, which is when Unit began focusing almost entirely on
increasing its liquids production. Third quarter 2012 oil production was
861,000 barrels, in comparison to 620,000 barrels for the same period of 2011,
an increase of 39%. NGLs production during the third quarter of 2012 was
684,000 barrels, an increase of 19% when compared to 578,000 barrels for the
same period of 2011. Third quarter 2012 natural gas production increased 1% to
11.7 billion cubic feet (Bcf) compared to 11.6 Bcf for the comparable quarter
of 2011. Total production for the first nine months of 2012 was 10.1 MMBoe.

Unit’s average natural gas price, including the effects of its hedges, for the
third quarter of 2012 decreased 23% to $3.40 per thousand cubic feet (Mcf) as
compared to $4.39 per Mcf for the third quarter of 2011. Unit’s average oil
price, including the effects of its hedges, for the third quarter of 2012
increased 6% to $91.07 per barrel compared to $86.19 per barrel for the third
quarter of 2011. Unit’s average NGLs price, including the effects of its
hedges, for the third quarter of 2012 was $21.34 per barrel compared to $45.40
per barrel for the third quarter of 2011, a decrease of 53%. For the first
nine months of 2012, Unit’s average natural gas price, including the effects
of its hedges, decreased 25% to $3.26 per Mcf as compared to $4.33 per Mcf for
the first nine months of 2011. Unit’s average oil price, including the effects
of its hedges, for the first nine months of 2012 was $92.96 per barrel
compared to $86.80 per barrel during the first nine months of 2011, a 7%
increase. Unit’s average NGLs price, including the effects of its hedges, for
the first nine months of 2012 was $30.70 per barrel compared to $43.72 per
barrel during the first nine months of 2011, a 30% decrease.

For the remainder of 2012, Unit has hedges in place for approximately 6,100
Bbls per day of oil production and approximately 50,000 MMBtu per day of
natural gas production. The oil production is hedged under swap contracts at
an average price of $97.55 per barrel. The natural gas production is hedged
under swap contracts at a comparable average NYMEX price of $5.09. The average
basis differential for the applicable swap is ($0.28). For the fourth quarter
of 2012, Unit has natural gas liquids hedges covering 380 Bbls per day at
$50.28 per barrel.

For 2013, Unit has hedged 5,500 Bbls per day of its oil production and 100,000
MMBtu per day of natural gas production. The oil production is hedged under
swap contracts at an average price of $99.71 per barrel. Of the natural gas
production, 80,000 MMBtu per day is hedged with swaps and 20,000 MMBtu per day
is hedged with a collar. The swap transactions were done at a comparable
average NYMEX price of $3.65. The collar transaction was done at a comparable
average NYMEX floor price of $3.25 and ceiling price of $3.72.

The following table illustrates Unit’s production and certain results for the
periods indicated:

            3^rd     2^nd     1^st     4^th     3^rd     2^nd     1^st     4^th    3^rd
              Qtr 12    Qtr 12    Qtr 12    Qtr 11    Qtr 11    Qtr 11    Qtr 11    Qtr 10   Qtr 10
Oil and NGL
Production,  1,545.8  1,460.2  1,375.2  1,359.9  1,197.5  1,158.6  1,034.0  925.5   756.5
MBbl
Natural Gas
Production,  11.7     11.3     11.4     11.4     11.6     10.9     10.2     10.6    10.4
Bcf
Production,  3,498    3,341    3,275    3,255    3,123    2,983    2,739    2,698   2,478
MBoe
Production,  38.0     36.7     36.0     35.4     33.9     32.8     30.4     29.3    27.0
MBoe/day
Realized
price, Boe   $37.99   $38.49   $40.51   $42.65   $41.75   $42.23   $40.00   $41.58  $38.16
(1)

(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
                                                                                   

In the Marmaton play, located in Beaver County, Oklahoma, Unit’s net
production for the third quarter of 2012 increased approximately 26% over the
second quarter of 2012. The average net daily production for the third quarter
was approximately 2,908 barrels of oil per day, 1,538 Mcf per day and 763
barrels of NGLs per day, for an equivalent rate of 3,927 Boe per day. For the
first nine months of 2012, 21 new operated “short” lateral (4500’) and two
“extended” lateral (9500’) horizontal wells had first oil and gas sales. The
30-day initial production rate for the short lateral wells averaged 332 Boe
per day and the extended laterals averaged 765 Boe per day. A third extended
lateral well is currently drilling and plans are to drill one to two
additional extended laterals in the fourth quarter of 2012. Currently, Unit
has two drilling rigs working in this play which should result in first oil
and gas sales on 26 to 30 short lateral wells and four to five extended
lateral wells for 2012. Unit currently has leases on approximately 112,000 net
acres in the play.

In the Granite Wash (GW) play, located in the Texas Panhandle, net production
for the third quarter averaged approximately 61 MMcfe per day, consisting of
approximately 50% liquids which accounts for approximately 27% of Unit’s
overall production. For the first nine months of 2012, Unit completed 22
operated GW horizontal wells as compared to 14 wells for the same period in
2011. For 2012, Unit anticipates completing approximately 30 wells. Unit’s
plan for its overall GW program is to increase from the two rigs currently
running to four rigs in January 2013 and then to six rigs around July 2013.
The rig locations will be split between the recently acquired Noble leasehold
and Unit’s existing leasehold; however, there is the flexibility to move rigs
to either area as needed since the majority of the leasehold is held by
production. Unit currently has leases on approximately 48,000 net acres in the
play.

In the Wilcox play, located in southeast Texas, Unit previously announced a
significant multi-zone, deeper Wilcox Field discovery that has estimated
potential resource reserves of 229 Bcfe gross and 159 Bcfe net with
approximately 43% consisting of liquids. During the third quarter, Unit
drilled and completed the fourth well in the field located approximately one
mile west of the initial wells. The well encountered an estimated 235 feet of
Wilcox potential oil and gas pay across seven intervals and is currently
producing from only one zone with 16 feet of perforations in a Lower Wilcox
sand at a depth of approximately 14,100 feet. The well was fracture stimulated
and had first sales in August 2012 at an initial potential of 3,000 Mcf per
day, 115 barrels of oil per day and 250 barrels of NGLs per day with 8,500
pounds of flowing tubing pressure. Unit is currently drilling the fifth field
well and anticipates drilling four to six additional wells in the field during
2013.

In the Mississippian play, located in Reno County, Kansas, Unit is continuing
to test its first horizontal well. The well drilled to a total measured depth
of 8,115’ including a 3,532’ lateral and was placed on production after
fracture stimulation in mid May 2012. Current plans are to continue to test
the well through the end of this year to obtain data for estimating ultimate
well reserves. Unit has drilled a second well, located approximately eight
miles from the first well, to a total measured depth of 8,130’ including a
3,870’ lateral. The well is scheduled to be fracture stimulated in November.
Unit plans to drill two more wells in the general area in the fourth quarter
2012. Unit currently has leased approximately 100,000 net acres in the
Mississippian play, primarily in Kansas.

On September 18, 2012, Unit closed on the previously announced agreement to
acquire certain oil and natural gas assets from Noble Energy, Inc. The amount
paid at closing was $594.5 million. The properties included approximately
84,000 net acres primarily in the Granite Wash, Cleveland, and various other
plays in western Oklahoma and the Texas Panhandle. The effective date of this
acquisition was April 1, 2012. As of the effective date, the estimated proved
reserves of the subject properties was 44.0 MMBoe, and the estimated average
daily net production was 10.0 MBoe. The acquisition adds approximately 25,000
net acres to Unit’s Granite Wash core area in the Texas Panhandle with
significant resource potential, including approximately 600 potential
horizontal drilling locations. The acreage is characterized by high working
interest and operatorship, and 95% of the acreage is held by production. Unit
also received four natural gas gathering systems as part of the transaction.

On September 28, 2012, Unit closed on its previously announced agreement to
sell its interest in certain of its Bakken properties to QEP Energy, a wholly
owned subsidiary of QEP Resources, Inc. The proceeds at closing were $226.6
million. As of the effective date of July 1, 2012, the estimated proved
reserves of the divested properties were 5.7 MMBoe, while the second quarter
average daily production for these properties was 1,044 Boe per day. The
properties total 4,756 net acres, representing approximately 35% of Unit’s
total acreage in the Bakken play.

Pinkston said: “We are excited about the Noble acquisition and the growth
opportunities that it will provide us. This acquisition will more than double
our acreage in our Granite Wash Texas Panhandle core area. It will also
provide us with additional inventory of drilling opportunities that will allow
us to significantly grow our production in the Anadarko Basin focused on oil-
and liquids-rich gas targets. Our recent divestiture of non-core properties
was a strategic move to enhance our overall liquidity for future growth
opportunities. Unit’s annual production guidance for 2012, including the
impact of the Noble acquisition, is approximately 13.9 to 14.2 MMBoe, an
increase of 15% to 17% over 2011.”

MID-STREAM SEGMENT INFORMATION

  *Increased third quarter 2012 liquids sold per day volumes, processed
    volumes per day, and gathered volumes per day by 28%, 28% and 22%,
    respectively, over the third quarter of 2011.
  *A new gas gathering system and processing plant in Noble and Kay counties
    in Oklahoma, known as the Bellmon system, is completed and operating.
    Extensions are underway to connect to third party producers.

Third quarter of 2012 per day processed volumes were 166,652 MMBtu while
liquids sold volumes were 576,889 gallons per day, an increase of 28% for
both, over the third quarter of 2011. Third quarter 2012 per day gathered
volumes were 277,806 MMBtu, an increase of 22% over the third quarter of 2011.
Operating profit (as defined in the Selected Financial and Operational
Highlights) for the third quarter was $6.7 million, a decrease of 10% from the
third quarter of 2011 and a decrease of 10% from the second quarter of 2012.
The decreases were primarily due to lower liquids volumes recovered between
quarters.

The following table illustrates certain results from this segment’s operations
for the periods indicated:

            3^rd     2^nd     1^st     4^th     3^rd     2^nd     1^st     4^th     3^rd
              Qtr 12    Qtr 12    Qtr 12    Qtr 11    Qtr 11    Qtr 11    Qtr 11    Qtr 10    Qtr 10
Gas
gathered     277,806  300,602  251,276  257,398  228,247  190,921  185,730  188,252  183,161
MMBtu/day
Gas
processed    166,652  177,407  154,825  156,721  129,820  90,737   86,445   85,195   84,175
MMBtu/day
Liquids
sold         576,889  629,350  522,829  511,410  449,604  356,484  328,333  291,186  260,519
Gallons/day
                                                                                    

Pinkston said: “Our operating profit decreased 10% in the third quarter
compared to the second quarter of 2012 due to lower liquids volumes recovered
between the quarters. Liquids sold per day volumes in the third quarter of
2012 decreased 8% from the liquids sold volumes in the second quarter of 2012.
During the second quarter of 2012, we completed the installation of our fifth
processing plant in our Hemphill County, Texas facility. We now have the
capacity to process 160 MMcf per day of our own and third party Granite Wash
natural gas production. In the Mississippian play in north central Oklahoma, a
new gas gathering system and processing plant in Noble and Kay counties, known
as the Bellmon system, was completed and began operating late in the second
quarter. This system initially consists of approximately 10 miles of 12” and
16” pipe with a 10 MMcf per day gas processing plant that will be upgraded to
a 30 MMcf per day gas processing plant in the first quarter of 2013. We are
also connecting our existing Remington gathering system to the new Bellmon
system. Connecting these two systems will require laying approximately 26
miles of pipeline and installing related compression which is scheduled to be
completed by the end of this year. Also at our new Bellmon system, we are in
the process of extending the system approximately 20 miles to connect to
third-party producers. We anticipate these extensions will be completed in the
fourth quarter of 2012. In addition to these construction projects, we are in
the process of laying a liquids line from our Bellmon facility to Medford,
Oklahoma. This project consists of approximately 24 miles of 6” pipe and is
scheduled to be completed by the end of 2012.”

“We are continuing to expand operations in the Appalachian region.
Construction continues on an additional gathering facility in Allegheny and
Butler counties, Pennsylvania, known as the Pittsburgh Mills system. The first
phase of this project consists of approximately seven miles of gathering
pipeline and a compressor station. Five wells were brought on during the
second quarter of 2012. The current gathered volumes are 15 MMcf per day from
six wells connected to this system. Construction of the first phase has been
completed, and we anticipate connecting five new wells in the fourth quarter
of this year. Construction activity for expansion of this pipeline continues
as the producer is maintaining its drilling activity.”

FINANCIAL INFORMATION

Unit ended the third quarter of 2012 with long-term debt of $645.2 million,
and a debt to capitalization ratio of 24%. On July 24, 2012, Unit completed a
private offering to eligible purchasers of $400 million aggregate principal
amount of senior subordinated notes due 2021, with an interest rate of 6.625%
per year. The notes were sold at 98.75% of par plus accrued interest from May
15, 2012. Unit used the net proceeds to partially finance the acquisition from
Noble. Also in conjunction with the acquisition, Unit increased commitments
under its existing credit facility from $250 million ($600 million borrowing
base) to $500 million ($800 million borrowing base).

MANAGEMENT COMMENT

Larry Pinkston said: “We are pleased with the operating results of the third
quarter and first nine months of 2012. We especially believe the Noble
acquisition will be an important growth step for Unit going forward. We plan
to accelerate the drilling activity in the acquired properties as well as our
other Granite Wash acreage over the next 12 to 18 months using up to six rigs
from our contract drilling segment, and we plan to operate the acquired
gathering systems and, as appropriate, replace existing third party processing
contracts beginning in 2015. We anticipate that this acquisition will
immediately be accretive to cash flow and to earnings beginning in 2013. We
are optimistic about the remainder of 2012 and the outlook for 2013. We are
well positioned, especially given the recent financing arrangements and
property divestitures we have completed, to take advantage of growth
opportunities that may arise for our business segments.”

WEBCAST

Unit will webcast its third quarter earnings conference call live over the
Internet on November 1, 2012 at 10:00 a.m. Central Time (11:00 a.m. Eastern).
To listen to the live call, please go to
http://www.unitcorp.com/investor/calendar.htm 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.

                             
Unit Corporation

Selected Financial and Operations Highlights

(In thousands except per share and operations data)
                                                                             
                               Three Months Ended      Nine Months Ended
                               September 30,           September 30,
                             2012       2011       2012       2011
Statement of Operations:                                         
Revenues:
Contract drilling              $ 133,420   $ 128,927   $ 421,198   $ 342,098
Oil and natural gas              131,420     134,897     397,745     376,393
Gas gathering and processing     52,935      60,688      159,977     144,820
Other, net                      (15     )  (667    )  1,160      (566    )
Total revenues                  317,760    323,845    980,080    862,745
                                                                             
Expenses:
Contract drilling:
Operating costs                  72,988      73,004      223,980     190,086
Depreciation                     20,094      20,818      62,660      57,333
Oil and natural gas:
Operating costs                  36,147      29,598      105,035     93,796
Depreciation, depletion and      44,489      47,195      153,839     132,013
amortization
Impairment of oil and            ---         ---         115,874     ---
natural gas properties
Gas gathering and
processing:
Operating costs                  46,267      53,299      136,243     119,143
Depreciation and                 5,884       4,017       16,330      11,627
amortization
General and administrative       8,434       7,800       23,814      22,188
Interest, net                   7,087      1,351      11,455     2,078
Total expenses                  241,390    237,082    849,230    628,264
Income Before Income Taxes      76,370     86,763     130,850    234,481
                                                                             
Income Tax Expense
(Benefit):
Current                          2,516       (3,949  )   450         (3,949  )
Deferred                        27,268     37,352     50,677     94,224
Total income taxes              29,784     33,403     51,127     90,275
                                                                             
Net Income                     $ 46,586    $ 53,360    $ 79,723    $ 144,206
                                                                             
Net Income per Common Share:
Basic                          $ 0.97      $ 1.12      $ 1.66      $ 3.03
Diluted                        $ 0.97      $ 1.11      $ 1.66      $ 3.01
                                                                             
Weighted Average Common
Shares Outstanding:
Basic                            47,938      47,687      47,891      47,642
Diluted                          48,201      47,968      48,106      47,932
                                                                             

                                                              
                                               September 30,     December 31,
                                             2012              2011
Balance Sheet Data:
Current assets                                 $  210,084        $ 228,465
Total assets                                   $  3,821,083      $ 3,256,720
Current liabilities                            $  247,447        $ 212,750
Long-term debt                                 $  645,154        $ 300,000
Other long-term liabilities                    $  165,384        $ 113,830
Deferred income taxes                          $  734,122        $ 683,123
Shareholders’ equity                           $  2,028,976      $ 1,947,017
                                               
                                               Nine Months Ended September 30,
                                             2012              2011
Statement of Cash Flows Data:
Cash Flow From Operations before Changes in    $  499,609        $ 450,725
Operating Assets and Liabilities (1)
Net Change in Operating Assets and               12,531         (32,874   )
Liabilities
Net Cash Provided by Operating Activities      $  512,140       $ 417,851   
Net Cash Used in Investing Activities          $  (888,597   )   $ (583,790  )
Net Cash Provided by Financing Activities      $  376,645        $ 165,740
                                                                 

                                                
                     Three Months Ended             Nine Months Ended
                     September 30,                  September 30,
                   2012           2011          2012          2011
Contract
Drilling                                                       
Operations Data:
Rigs Utilized            73.4           78.9           77.2           74.0
Operating                45%            43%            47%            44%
Margins (2)
Operating Profit
Before               $   60.4        $  55.9        $  197.2       $  152.0
Depreciation (2)
($MM)
                                                                      
Oil and Natural
Gas Operations
Data:
Production:
Oil – MBbls              861            620            2,367          1,767
Natural Gas              684            578            2,014          1,623
Liquids - MBbls
Natural Gas -            11,716         11,553         34,403         32,730
MMcf
Average Prices:
Oil price per        $   91.07       $  86.19       $  92.96       $  86.80
barrel received
Oil price per
barrel received,     $   87.38       $  89.47       $  91.93       $  93.75
excluding hedges
NGLs price per       $   21.34       $  45.40       $  30.70       $  43.72
barrel received
NGLs price per
barrel received,     $   20.75       $  46.33       $  29.61       $  44.65
excluding hedges
Natural Gas
price per Mcf        $   3.40        $  4.39        $  3.26        $  4.33
received
Natural Gas
price per Mcf        $   2.50        $  4.01        $  2.29        $  3.94
received,
excluding hedges
Operating Profit
Before DD&A and      $   95.3        $  105.3       $  292.7       $  282.6
impairment (2)
($MM)
                                                                      
Mid-Stream
Operations Data:
Gas Gathering -          277,806        228,247        276,566        201,788
MMBtu/day
Gas Processing -         166,652        129,820        166,296        102,493
MMBtu/day
Liquids Sold –           576,889        449,604        576,358        378,585
Gallons/day
Operating Profit
Before
Depreciation and     $   6.7         $  7.4         $  23.7        $  25.7
Amortization (2)
($MM)
                                                                      
(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, impairment,general and administrative and interest expense.
Operating margins are calculated by dividing operating profit by segment
revenue.
                                                                      

Non-GAAP Financial Measures

We report our financial results in accordance with generally accepted
accounting 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, diluted earnings per share excluding
the effect of the impairment of our oil and natural gas properties, 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.

Below is a reconciliation of GAAP financial measures to non-GAAP financial
measures for the three and nine months ended September 30, 2012 and 2011.
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 Diluted Earnings per Share

Excluding the Effect of Impairment of Oil and Natural Gas Properties
                                                           
                                  Three Months Ended       Nine Months Ended
                                  September 30,            September 30,
                                  2012       2011         2012     2011
                                  (In thousands)
Net income excluding impairment
of oil and natural gas
properties:
Net income                        $  46,586   $  53,360  $ 79,723    $ 144,206
Add:
Impairment of oil and natural
gas properties (net of income       ---        ---      72,132     ---
tax)
Net income excluding impairment
of oil and natural gas            $  46,586   $  53,360  $ 151,855   $ 144,206
properties
                                                                       
Diluted earnings per share
excluding impairment of oil and
natural gas properties:
Diluted earnings per share        $  0.97     $  1.11    $ 1.66      $ 3.01
Add:
Diluted earnings per share from
impairment of oil and natural       ---        ---      1.50       ---
gas properties
Diluted earnings per share
excluding impairment of oil and   $  0.97     $  1.11    $ 3.16      $ 3.01
natural gas properties
                                                                       

________________

We have included the net income excluding impairment of oil and natural gas
properties and diluted earnings per share excluding 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.

Non-GAAP Financial Measures (continued)

                                                       
Unit Corporation

Reconciliation of Cash Flow From Operations Before Changes in Operating Assets
and Liabilities
                                                         
                                                         Nine Months Ended

                                                         September 30,
                                                         2012        2011
                                                         (In thousands)
Net cash provided by operating activities                $ 512,140   $ 417,851
Subtract:
Net change in operating assets and liabilities            (12,531 )  32,874
Cash flow from operations before changes in operating    $ 499,609   $ 450,725
assets and liabilities
                                                                       

________________

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
                                                         
                     Three Months Ended                  Nine Months Ended
                     June 30,   September 30,           September 30,
                     2012        2012       2011        2012       2011
                     (In thousands)
Contract drilling    $ 146,872   $ 133,420   $ 128,927   $ 421,198   $ 342,098
revenue
Contract drilling     74,819     72,988     73,004     223,980    190,086
operating cost
Operating profit
from contract          72,053      60,432      55,923      197,218     152,012
drilling
Add:
Elimination of
intercompany rig      4,669      3,983      4,820      12,936     14,955
profit
Operating profit
from contract
drilling before        76,722      64,415      60,743      210,154     166,967
elimination of
intercompany rig
profit
Contract drilling     6,893      6,660      7,220      20,884     20,129
operating days
Average daily
operating margin
before elimination   $ 11,130    $ 9,672     $ 8,413     $ 10,063    $ 8,295
of intercompany
rig profit
                                                                       

________________

We have included the average daily operating margin before elimination of
intercompany rig profit 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.

Contact:

Unit Corporation
David T. Merrill,918-493-7700
Chief Financial Officer and Treasurer
www.unitcorp.com