Unit Corporation (NYSE: UNT) reported a net loss of $19.3 million, or
$0.40 per diluted share, for the three months ended June 30, 2012,
compared to net income of $49.8 million, or $1.04 per diluted share, for
the second quarter of 2011. 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 second quarter of 2012 would have been $52.8
million, or $1.10 per diluted share, a 6% increase over the second
quarter 2011 (see Non-GAAP Financial Measures below). Total revenues for
the second quarter of 2012 were $329.9 million (45% contract drilling,
40% oil and natural gas, and 15% mid-stream), compared to $291.5 million
(40% contract drilling, 45% oil and natural gas, and 15% mid-stream) for
the second quarter of 2011.

For the first six months of 2012, Unit reported net income of $33.1
million, or $0.69 per diluted share. For the same period in 2011, net
income was $90.8 million, or $1.89 per diluted share. Excluding the
effect of the second quarter 2012 ceiling test write down, net income
for the first six months would have been $105.3 million, or $2.19 per
diluted share, an increase of 16% over the same period in 2011 (see
Non-GAAP Financial Measures below). Total revenues for the first six
months of 2012 were $662.3 million (43% contract drilling, 40% oil and
natural gas, and 16% mid-stream), compared to $538.9 million (40%
contract drilling, 45% oil and natural gas, and 15% mid-stream) for the
first six months of 2011.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the second quarter of 2012
was 76.7, an increase of 5% over the second quarter of 2011, and a
decrease of 6% from the first quarter of 2012. Per day drilling rig
rates for the second quarter of 2012 averaged $20,128, an increase of
7%, or $1,267, from the second quarter of 2011, and an increase of 1%,
or $290, from the first quarter of 2012. Average per day operating
margin for the second quarter of 2012 was $11,130 (before elimination of
intercompany drilling rig profit of $4.7 million). This compares to
$8,370 (before elimination of intercompany drilling rig profit of $5.1
million) for the second quarter of 2011, an increase of 33%, or $2,760.
As compared to the first quarter of 2012 ($9,414 before elimination of
intercompany drilling rig profit of $4.3 million), second quarter 2012
operating margin increased 18% or $1,716 (in each case with regard to
the elimination of intercompany drilling rig profit see Non-GAAP
Financial Measures below). Approximately $2,188 per day of the second
quarter 2012 average operating margin was the result of early
termination fees resulting from the cancellation of certain long-term
contracts.

For the first six months of 2012, Unit averaged 79.1 drilling rigs
working, up 10% from 71.6 drilling rigs working during the first six
months of 2011. Average per day operating margin for the first six
months of 2012 was $10,246 (before elimination of intercompany drilling
rig profit of $9.0 million) as compared to $8,229 (before elimination of
intercompany drilling rig profit of $10.1 million) for the first six
months of 2011, an increase of 25% (in each case with regard to the
elimination of intercompany drilling rig profit see Non-GAAP Financial
Measures below). Approximately $1,109 per day of the first six 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: “We
are pleased with the results that our contract drilling segment has been
able to attain. 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 97% of our drilling rigs working today are drilling
for oil or natural gas liquids (NGLs) and approximately 96% are drilling
horizontal or directional wells. During the second quarter of 2012, we
placed a new 1,500 horsepower, diesel-electric drilling rig in North
Dakota under a three-year contract. Currently, we have 128 drilling rigs
in our fleet, of which 73 are under contract. Long-term contracts
(contracts with original terms ranging from six months to two years in
length) are in place for 39 of those 73 drilling rigs. Of these
contracts, 13 are up for renewal during the third quarter of 2012, nine
during the fourth quarter of 2012, and 17 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 are approximately $15 million.”

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

    2nd Qtr 12   1st Qtr 12   4th Qtr 11   3rd Qtr 11   2nd Qtr 11   1st Qtr 11   4th Qtr 10   3rd Qtr 10   2nd Qtr 10
Rigs   128   127   127   126   123   122   121   123   123
Utilization   60%   64%   65%   63%   60%   58%   59%   54%   47%
                 

OIL AND NATURAL GAS SEGMENT INFORMATION

  • Second quarter 2012 production was 3.3 MMBoe, an increase of 12% over
    the second quarter 2011.
  • 44% of second quarter 2012 production was oil and NGLs compared to 39%
    for the second quarter of 2011.
  • Production guidance for 2012, excluding the impact of acquisitions, is
    13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011.
  • Unit has drilled a significant multi-zone, deeper Wilcox field
    discovery located in Polk County, Texas.

The second quarter marks the tenth 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% and 42% of total equivalent production during the second
and first quarters of 2012, respectively. Second quarter 2012 total
equivalent production increased 12% to 3.3 MMBoe over the second quarter
of 2011, while total liquids production for the second quarter of 2012
increased 26% over the comparable quarter of 2011. Second quarter 2012
oil production was 786,000 barrels, in comparison to 591,000 barrels for
the same period of 2011, an increase of 33%. NGLs production during the
second quarter of 2012 was 674,000 barrels, an increase of 19% when
compared to 567,000 barrels for the same period of 2011. Second quarter
2012 natural gas production increased 3% to 11.3 billion cubic feet
(Bcf) compared to 10.9 Bcf for the comparable quarter of 2011. Total
production for the first six months of 2012 was 6.6 MMBoe.

Unit’s average natural gas price, including the effects of its hedges,
for the second quarter of 2012 decreased 30% to $3.03 per thousand cubic
feet (Mcf) as compared to $4.30 per Mcf for the second quarter of 2011.
Unit’s average oil price, including the effects of its hedges, for the
second quarter of 2012 increased 3% to $92.43 per barrel compared to
$89.77 per barrel for the second quarter of 2011. Unit’s average NGLs
price, including the effects of its hedges, for the second quarter of
2012 was $32.34 per barrel compared to $45.49 per barrel for the second
quarter of 2011, a decrease of 29%. For the first six months of 2012,
Unit’s average natural gas price, including the effects of its hedges,
decreased 26% to $3.19 per Mcf as compared to $4.29 per Mcf for the
first six months of 2011. Unit’s average oil price, including the
effects of its hedges, for the first six months of 2012 was $94.04 per
barrel compared to $87.14 per barrel during the first six months of
2011, an 8% increase. Unit’s average NGLs price, including the effects
of its hedges, for the first six months of 2012 was $35.53 per barrel
compared to $42.80 per barrel during the first six months of 2011, a 17%
decrease.

For 2012, Unit hedged 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 2012, Unit
hedged NGLs of 1,966 Bbls per day in the first quarter, 926 Bbls per day
in the second quarter, and 380 Bbls per day in the third and fourth
quarters. The NGLs are hedged under swap contracts at an average price
of $42.53 per barrel in the first quarter, $41.15 per barrel in the
second quarter, $51.28 per barrel in the third quarter, and $50.28 per
barrel in the fourth quarter.

For 2013, Unit has hedged 5,000 Bbls per day of its oil production and
80,000 MMBtu per day of natural gas production. The oil production is
hedged under swap contracts at an average price of $100.19 per barrel.
Of the natural gas production, 60,000 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 $3.56. 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:

    2nd Qtr 12   1st Qtr 12   4th Qtr 11   3rd Qtr 11   2nd Qtr 11   1st Qtr 11   4th Qtr 10   3rd Qtr 10   2nd Qtr 10
Oil and NGL Production, MBbl    

1,460.2

   

1,375.2

   

1,359.9

   

1,197.5

   

1,158.6

   

1,034.0

   

925.5

   

756.5

   

708.6

Natural Gas Production, Bcf

   

11.3

   

11.4

   

11.4

   

11.6

   

10.9

   

10.2

   

10.6

   

10.4

   

9.7

Production, MBoe

   

3,341

   

3,275

   

3,255

   

3,123

   

2,983

   

2,739

   

2,698

   

2,478

   

2,325

Production, MBoe/day

   

36.7

   

36.0

   

35.4

   

33.9

   

32.8

   

30.4

   

29.3

   

27.0

   

25.6

Realized price, Boe (1)

 

$

38.49

 

$

40.51

 

$

42.65

 

$

41.75

 

$

42.23

 

$

40.00

 

$

41.58

 

$

38.16

 

$

38.22

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

In Polk County, Texas, Unit has drilled a significant multi-zone, deeper
Wilcox field discovery. To date, Unit has drilled four wells on the
prospect averaging 226 feet of potential net pay with an average working
interest of approximately 94%. First production in the new discovery
started in July 2011 and currently three wells are producing at a
combined approximate rate of 9.7 MMcf per day, 260 barrels of oil per
day and 1,090 barrels of NGLs per day, or an equivalent rate of 17.8
MMcfe per day from an average of 26 feet of perforations per well. The
fourth well, which is approximately 5,200 feet away from the other three
wells, is currently being completed for production. Unit’s estimated
total net resource potential for this prospect area is estimated at
approximately 159 Bcfe, consisting of approximately 2.2 million barrels
of oil, 9.2 million barrels of NGLs, and 90.4 Bcf of natural gas, of
which approximately 16% is currently proved reserves. Unit plans to
drill two additional step-out wells in this prospect in 2012 and
anticipates drilling four infill development wells in 2013.

On July 10, 2012, Unit entered into an agreement to acquire certain oil
and natural gas assets from Noble Energy, Inc. for $617.1 million in
cash, subject to certain possible adjustments. The properties include
approximately 84,000 net acres primarily in the Granite Wash, Cleveland,
and Marmaton plays in western Oklahoma and the Texas Panhandle. The
effective date of this acquisition is April 1, 2012, and closing is
anticipated to be in September 2012, subject to customary closing
conditions. As of the effective date, the estimated proved reserves of
the subject properties is 44.0 MMBoe, and the estimated average daily
net production is 10.0 MBoe. The acquisition will add approximately
25,000 net acres to Unit’s Granite Wash core area in the Texas Panhandle
with significant resource potential, including 617 potential horizontal
drilling locations. The acreage is characterized by high working
interest and operatorship, and 95% of the acreage is held by production.
Unit will also receive two natural gas gathering systems as part of the
transaction.

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
Wilcox play continues to deliver very exciting results. The significance
of the multi-zone, deeper field discovery further confirms our
commitment to the Wilcox play. Unit’s annual production guidance for
2012, excluding the impact of the Noble acquisition, is approximately
13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011. Including the
anticipated fourth quarter production from the Noble acquisition, Unit
estimates its annual production guidance for 2012 to be 14.1 to 14.4
MMBoe, an increase of 17% to 19% over 2011.”

MID-STREAM SEGMENT INFORMATION

  • Increased second quarter 2012 liquids sold per day volumes, processed
    volumes per day, and gathered volumes per day by 77%, 96% and 57%,
    respectively, over the second quarter of 2011.
  • A new gas gathering system and processing plant in Noble and Kay
    counties in Oklahoma, known as the Bellmon system, was completed and
    began operating late in the second quarter.

Second quarter of 2012 per day processed volumes were 177,407 MMBtu
while liquids sold volumes were 629,350 gallons per day, an increase of
96% and 77%, respectively, over the second quarter of 2011. Second
quarter 2012 per day gathered volumes were 300,602 MMBtu, an increase of
57% over the second quarter of 2011. Operating profit (as defined in the
Selected Financial and Operational Highlights) for the second quarter
was $7.4 million, a decrease of 3% from the second quarter of 2011 and a
decrease of 24% from the first quarter of 2012. The decreases were
primarily due to decreases in the average price for natural gas and
natural gas liquids.

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

    2nd Qtr 12   1st Qtr 12   4th Qtr 11   3rd Qtr 11   2nd Qtr 11   1st Qtr 11   4th Qtr 10   3rd Qtr 10   2nd Qtr 10

Gas gathered MMBtu/day

 

300,602

 

251,276

 

257,398

 

228,247

 

190,921

 

185,730

 

188,252

 

183,161

 

183,858

Gas processed MMBtu/day

 

177,407

 

154,825

 

156,721

 

129,820

 

90,737

 

86,445

 

85,195

 

84,175

 

82,699

Liquids sold Gallons/day

 

629,350

 

522,829

 

511,410

 

449,604

 

356,484

 

328,333

 

291,186

 

260,519

 

279,736

                 

Pinkston said: “Our operating profit decreased 24% in the second quarter
compared to the first quarter of 2012 due to a significant decline in
the average price for natural gas liquids. NGLs prices in the second
quarter of 2012 decreased 28% from the price received in the first
quarter of 2012. We are still experiencing strong volume growth in our
operations due to the number of well connects and upgrades and
expansions to our processing plants. We have 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 fourth quarter of 2012. We are also planning
to connect 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 planning to extend the system approximately 14
miles to connect to a third-party producer. We anticipate this extension
will be completed in the fourth quarter of 2012.

“We are continuing to expand operations in the Appalachian region.
Construction continues on our 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 23 MMcf per day
from six wells connected to this system. Construction activity for
expansion of this pipeline continues as the producer is maintaining its
drilling activity.”

FINANCIAL INFORMATION

Unit ended the second quarter of 2012 with working capital of $41.5
million, long-term debt of $332.9 million, and a debt to capitalization
ratio of 14%. 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 intends to use the net proceeds to partially finance the
pending acquisition from Noble. Also in conjunction with the
acquisition, Unit intends to increase commitments under its existing
credit facility from $250 million ($600 million borrowing base) up to
$750 million ($800 million borrowing base).

MANAGEMENT COMMENT

Larry Pinkston said: “We are pleased with the operating results of the
second quarter and first half of 2012. We believe the Noble acquisition
is an important growth step for Unit and represents a unique opportunity
that benefits all three of our business segments. For our upstream
business segment, it will more than double our acreage in the Granite
Wash Texas Panhandle core area, a highly prolific liquids-rich fairway
in the Anadarko Basin. We plan to accelerate the drilling activity in
the acquired properties over the next 12 to 18 months using seven 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 we
are well positioned, especially given the recent financing arrangements
we have completed, to take advantage of growth opportunities that may
arise for our business segments.”

WEBCAST

Unit will webcast its second quarter earnings conference call live over
the Internet on July 31, 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
potential that the acquisition discussed in this release may not close,
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 Six Months Ended
June 30, June 30,
    2012   2011   2012   2011
Statement of Operations:
Revenues:
Contract drilling $ 146,872 $ 115,183 $ 287,778 $ 213,171
Oil and natural gas 132,553 131,662 266,325 241,496
Gas gathering and processing 49,747 44,368 107,042 84,132
Other, net   720     282   1,175     101
Total revenues   329,892     291,495   662,320     538,900
 
Expenses:
Contract drilling:
Operating costs 74,819 64,238 150,992 117,082
Depreciation 21,238 19,218 42,566 36,515
Oil and natural gas:
Operating costs 33,279 33,417 68,888 64,198

Depreciation, depletion and amortization

57,153 44,550 109,350 84,818

Impairment of oil and natural gas properties

115,874

115,874

Gas gathering and processing:
Operating costs 42,363 36,789 89,976 65,844

Depreciation and amortization

5,312 3,837 10,446 7,610
General and administrative 8,376 7,496 15,380 14,388
Interest, net   2,542     673   4,368     727
Total expenses   360,956     210,218   607,840     391,182
Income (Loss) Before Income Taxes   (31,064 )   81,277   54,480     147,718
 
Income Tax Expense (Benefit):
Current (2,066 ) (2,066 )
Deferred   (9,696 )   31,458   23,409     56,872
Total income taxes   (11,762 )   31,458   21,343     56,872
 
Net Income (Loss) $ (19,302 ) $ 49,819 $ 33,137   $ 90,846
 

Net Income (Loss) per Common Share:

Basic $ (0.40 ) $ 1.05 $ 0.69 $ 1.91
Diluted $ (0.40 ) $ 1.04 $ 0.69 $ 1.89
 
Weighted Average Common
Shares Outstanding:
Basic 47,906 47,655 47,868 47,620
Diluted 47,906 47,983 48,113 47,944
 
 
  June 30,   December 31,
    2012   2011
Balance Sheet Data:
Current assets $ 236,871 $ 228,465
Total assets $ 3,353,437 $ 3,256,720
Current liabilities $ 195,333 $ 212,750
Long-term debt $ 332,900 $ 300,000
Other long-term liabilities $ 116,362 $ 113,830
Deferred income taxes $ 708,464 $ 683,123
Shareholders’ equity $ 2,000,378 $ 1,947,017
 
 
Six Months Ended June 30,
    2012   2011
Statement of Cash Flows Data:
Cash Flow From Operations before Changes
in Operating Assets and Liabilities (1) $ 345,123 $ 284,726
Net Change in Operating Assets and Liabilities   (30,091 )   (25,216 )
Net Cash Provided by Operating Activities $ 315,032   $ 259,510  
Net Cash Used in Investing Activities $ (367,608 ) $ (351,942 )

Net Cash Provided by Financing Activities

$

52,826

$

92,296

 
 
  Three Months Ended   Six Months Ended
June 30, June 30,
    2012   2011   2012   2011
Contract Drilling Operations Data:    
Rigs Utilized 76.7 73.1 79.1 71.6
Operating Margins (2) 49 % 44 % 48 % 45 %
Operating Profit Before Depreciation (2) ($MM) $ 72.1 $ 50.9 $ 136.8 $ 96.1
 
Oil and Natural Gas Operations Data:
Production:
Oil – MBbls 786 591 1,506 1,147
Natural Gas Liquids – MBbls 674 567 1,330 1,046
Natural Gas – MMcf 11,287 10,946 22,688 21,178
Average Prices:

Oil price per barrel received

$ 92.43 $ 89.77 $ 94.04 $ 87.14

Oil price per barrel received, excluding hedges

$ 89.38 $ 101.02 $ 94.53 $ 96.06
NGLs price per barrel received $ 32.34 $ 45.49 $ 35.53 $ 42.80

NGLs price per barrel received, excluding hedges

$ 31.12 $ 46.58 $ 34.19 $ 43.72
Natural Gas price per Mcf received $ 3.03 $ 4.30 $ 3.19 $ 4.29

Natural Gas price per Mcf received, excluding hedges

$ 1.91 $ 3.97 $ 2.18 $ 3.91

Operating Profit Before DD&A and impairment (2) ($MM)

$

99.3

$

98.2

$

197.4

$

177.3

 
Mid-Stream Operations Data:
Gas Gathering – MMBtu/day 300,602 190,921 275,939 188,340
Gas Processing – MMBtu/day 177,407 90,737 166,116 88,603
Liquids Sold – Gallons/day 629,350 356,484 576,089 342,486

Operating Profit Before Depreciation and Amortization (2) ($MM)

$ 7.4 $ 7.6 $ 17.1 $ 18.3

(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, 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 six months ended June 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   Six Months Ended
June 30, June 30,
2012   2011 2012   2011
(In thousands)
Net income excluding impairment of oil and
natural gas properties:
Net income (loss) $ (19,302 ) $ 49,819 $ 33,137 $ 90,846
Add:
Impairment of oil and natural gas properties
(net of income tax)   72,132       72,132  
Net income excluding impairment of oil and
natural gas properties $ 52,830   $ 49,819 $ 105,269 $ 90,846
 
Diluted earnings per share excluding
impairment of oil and natural gas properties:
Diluted earnings per share
Add:

Diluted earnings per share from impairment

$ (0.40 ) $ 1.04 $ 0.69 $ 1.89
of oil and natural gas properties   1.50       1.50  
Diluted earnings per share excluding
impairment of oil and natural gas properties $ 1.10   $ 1.04 $ 2.19 $ 1.89

________________

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
   
Six Months Ended

June 30,

2012 2011
(In thousands)
Net cash provided by operating activities $ 315,032 $ 259,510
Subtract:
Net change in operating assets and liabilities   (30,091 )   (25,216 )
Cash flow from operations before changes
in operating assets and liabilities $ 345,123   $ 284,726  

________________

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 Six Months Ended
March 31, June 30, June 30,
2012 2012 2011 2012 2011
(In thousands)
Contract drilling revenue $ 140,906 $ 146,872 $ 115,183 $ 287,778 $ 213,171
Contract drilling operating cost   76,173   74,819   64,238   150,992   117,082
Operating profit from contract drilling 64,733 72,053 50,945 136,786 96,089
Add:
Elimination of intercompany rig profit   4,284   4,669   5,092   8,953   10,136
Operating profit from contract drilling
before elimination of intercompany
rig profit 69,017 76,722 56,037 145,739 106,225
Contract drilling operating days   7,331   6,893   6,695   14,224   12,909
Average daily operating margin before
elimination of intercompany rig profit $ 9,414 $ 11,130 $ 8,370 $ 10,246 $ 8,229

________________

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.

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