Unit Corporation Reports 2012 Third Quarter and First Nine Months Results

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

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

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 amortization		44,489			47,195			153,839		132,013
Impairment of oil and natural gas properties		—			—			115,874		—
Gas gathering and processing:
Operating costs		46,267			53,299			136,243		119,143
Depreciation and amortization		5,884			4,017			16,330		11,627
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 Operating Assets and Liabilities (1)	$	499,609		$	450,725
Net Change in Operating Assets and Liabilities		12,531			(32,874	)
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 Margins (2)		45%		43%		47%		44%
Operating Profit Before Depreciation (2) ($MM)	$	60.4	$	55.9	$	197.2	$	152.0

Oil and Natural Gas Operations Data:
Production:
Oil – MBbls		861		620		2,367		1,767
Natural Gas Liquids – MBbls		684		578		2,014		1,623
Natural Gas – MMcf		11,716		11,553		34,403		32,730
Average Prices:
Oil price per barrel received	$	91.07	$	86.19	$	92.96	$	86.80
Oil price per barrel received, excluding hedges	$	87.38	$	89.47	$	91.93	$	93.75
NGLs price per barrel received	$	21.34	$	45.40	$	30.70	$	43.72
NGLs price per barrel received, excluding hedges	$	20.75	$	46.33	$	29.61	$	44.65
Natural Gas price per Mcf received	$	3.40	$	4.39	$	3.26	$	4.33
Natural Gas price per Mcf received, excluding hedges	$	2.50	$	4.01	$	2.29	$	3.94
Operating Profit Before DD&A and impairment (2) ($MM)	$	95.3	$	105.3	$	292.7	$	282.6

Mid-Stream Operations Data:
Gas Gathering – MMBtu/day		277,806		228,247		276,566		201,788
Gas Processing – MMBtu/day		166,652		129,820		166,296		102,493
Liquids Sold – Gallons/day		576,889		449,604		576,358		378,585
Operating Profit Before Depreciation and Amortization (2) ($MM)	$	6.7	$	7.4	$	23.7	$	25.7

(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 tax)		—		—		72,132		—
Net income excluding impairment of oil and natural gas properties	$	46,586	$	53,360	$	151,855	$	144,206

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 gas properties		—		—		1.50		—
Diluted earnings per share excluding impairment of oil and natural gas properties	$	0.97	$	1.11	$	3.16	$	3.01

________________

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 assets and liabilities	$	499,609		$	450,725

________________

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

________________

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

Unit Corporation Reports 2012 Third Quarter and First Nine Months Results

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