Third graph, first sentence of release should read: Unit’s 2011 capital
expenditures budget is based on prices for oil and natural gas averaging
$82.00 per barrel and $4.60 per thousand cubic feet (Mcf) for the year.
(sted Unit’s 2011 capital expenditures budget is based on prices for oil
and natural gas averaging $82.00 per barrel and $4.60 per million cubic
feet (Mcf) for the year.)

The corrected release reads:


Unit Corporation (NYSE: UNT) announced today its initial 2011 capital
expenditures budget, 2010 total proved oil and natural gas reserves, as
well as certain operational updates for each of Unit’s three business
segments. This information is unaudited and preliminary. Audited final
results will be provided in Unit’s Annual Report on Form 10-K for the
year ended December 31, 2010.

2011 Capital Expenditure Budget

The 2011 capital expenditures budget for all of Unit’s business segments
is $605 million, an increase of 16% over estimated 2010 capital
expenditures, excluding acquisitions. Of this amount, $415 million is
budgeted for its oil and natural gas segment, which includes $357
million for drilling and completion activities, an 11% increase over
estimated 2010 capital expenditures, $143 million for its contract
drilling segment, a 20% increase over estimated 2010 capital
expenditures, and $47 million for its mid-stream segment, a 58% increase
over estimated 2010 capital expenditures.

Unit’s 2011 capital expenditures budget is based on prices for oil and
natural gas averaging $82.00 per barrel and $4.60 per thousand cubic
feet (Mcf) for the year. This budget is subject to adjustment for
various reasons including changes in commodity prices and industry
conditions. Funding for the 2011 capital expenditures budget is
anticipated to be mainly from internally generated cash flow and to a
lesser extent from borrowings under the company’s bank credit facility.

Oil and Natural Gas Segment Information

For 2010, this segment achieved the following results:

  • Year end proved reserves of 622.2 billion cubic feet equivalents
  • Oil and natural gas production of 59.2 Bcfe.
  • Replaced 176% of its 2010 production, with 158% through the drill bit.

2010 Total Proved Oil and Natural Gas Reserves

Total proved oil and naturalgas reserves at December 31, 2010
were 622.2 Bcfe of natural gas, consisting of 17.5 million barrels
(MMbls) of oil, 16.1 MMbls of natural gas liquids (NGLs) and 420.5 Bcf
of natural gas. This represents an 8% increase over 2009 year-end total
proved reserves. Between 2010 and 2009, Unit’s oil and NGLs reserves
increased 50% and 10%, respectively, while its natural gas reserves were
essentially unchanged. The change in the make up of Unit’s reserves at
December 31, 2010 is the direct result of the strategy implemented by
Unit at the beginning of 2009 to focus on oil or NGLs rich prospects.
Eighty percent of Unit’s proved oil and natural gas reserves are “proved
developed,” with the remaining 20% comprising “proved undeveloped”

Ryder Scott Company, L.P. (Ryder Scott), an independent reserve
engineering firm, audited Unit’s proved reserves. Their audit covered
properties that made up about 83% of the company’s total proved reserves
at year end 2010.

The following details the changes to Unit’s proved oil and natural gas
reserves after December 31, 2009:

Oil and NGLs Natural Gas Proved Reserves
(MMbls) (Bcf) (Bcfe)
Proved Reserves, at December 31, 2009 26.3 419.1 577.0
Revisions of previous estimates (1.1 ) (24.9 ) (31.6 )
Extensions, discoveries and other additions 10.0 65.4 125.3
Purchases of minerals in place 1.5 1.7 10.7
Production (3.1 ) (40.8 ) (59.2 )
Proved Reserves, at December 31, 2010 33.6 420.5 622.2

The estimated future net cash flow from Unit’s December 31, 2010 total
proved oil and natural gas reserves, before income taxes, is $2.4
billion. The present value of those reserves (before income taxes and
discounted at 10% (PV-10)) is about $1.3 billion. These value estimates
were made using the 12-month unweighted arithmetic average of the first
day of the month price for the periods January 1, 2010 through December
31, 2010. The resulting prices used (unescalated) were $79.43 per barrel
of oil, $49.35 per barrel of NGLs, and $4.38 per Mcf of natural gas,
adjusted for price differentials, for the estimated life of the
respective properties. PV-10 is a non-GAAP financial measure. See below
for the reconciliation of PV-10 to the standardized measure of
discounted future net cash flows as defined by GAAP.

Preliminary 2010 Production and Wells Drilled

Production during the fourth quarter of 2010 was 519,000 barrels of oil,
406,000 barrels of NGLs and 10.6 Bcf of natural gas, or 16.2 Bcfe, an
increase of 9% and 13% over the third quarter of 2010 and the fourth
quarter of 2009, respectively. Total production for 2010 was 59.2 Bcfe,
a decrease of 3% from the 60.7 Bcfe produced in 2009.

During 2010 Unit participated in the drilling of 167 wells compared to
95 wells in 2009, an increase of 76%.

Operational Updates

During 2010 in its Marmaton horizontal oil play located in Beaver
County, Oklahoma, Unit drilled 19 horizontal Marmaton wells with an
average working interest of 92% and participated in one outside operated
horizontal Marmaton well with a 50% working interest. Completion of many
of these wells was delayed until the beginning of the fourth quarter due
to the unavailability of third party fracturing services. Early in the
fourth quarter, Unit was able to obtain the needed fracturing services
and by year end 2010, had successfully fracture stimulated 11 of the 20
wells, and subsequently had first oil sales on ten of these wells in
late 2010. The initial 30-day average production rate for the ten wells
ranged from 80 barrels of oil equivalent (BOE) per day to 480 BOE per
day with an average rate of 230 BOE per day. The average ultimate
recovery for each of the ten completed wells is estimated to be 130
thousand BOE at an average completed well cost of approximately $2.8
million. The current cost to drill and complete new wells is estimated
at $2.5 million. Unit has secured frac dates for 2011, which should
catch up the wells waiting to be fracture stimulated as well as the new
wells that will be drilled. For 2011, Unit anticipates running a two
drilling rig program in this play that should result in 30 to 35 gross
wells at an approximate net cost of $52 million. Unit currently has
leases on approximately 60,000 net acres in this play.

In its Granite Wash (GW) play located in the Texas Panhandle, Unit
drilled and operated twelve horizontal wells with an average working
interest of 73% and four vertical wells with an average working interest
of 87%. In addition, Unit participated in 10 outside operated GW
horizontal wells, with an average working interest of approximately 12%,
located in the Texas Panhandle and Western Oklahoma. Focusing on the
operated horizontal wells, ten of the 12 completed wells had first oil
and gas sales during 2010, consisting of one well in each of the first
three quarters and seven wells during the fourth quarter. The GW
laterals completed in 2010 include three GW “A”, six GW “B”, one GW “C1”
and two GW “F” zones. In 2009, Unit also completed a well in the GW “C”.
This brings the total GW zones that have been successfully completed on
Unit’s leasehold to five and the plan is to test a sixth zone in the GW
“D” zone in 2011. Highlights from the completed 2010 wells include an
83% working interest in a GW “B” zone completion with an initial daily
peak rate of 1,135 barrels of oil per day, 662 barrels of natural gas
liquids (NGLs) per day and 6.2 MMcf per day or an equivalent daily rate
of approximately 17 MMcfe per day and a 30 day average daily rate of
14.3 MMcfe per day. The first GW “F” zone completion (100% working
interest) had a peak daily rate of 329 barrels of oil per day, 366
barrels of NGLs per day, and 3.4 MMcf per day, or an equivalent rate of
approximately 7.6 MMcfe per day and a 30 day average rate of 5.8 MMcfe
per day. The average daily peak rate for the 2010 completed wells was
approximately 8.0 MMcfe per day with oil and liquids accounting for
approximately 50% of the production stream at a completed well cost of
approximately $5.1 million. Unit expects to work three to four Unit
drilling rigs drilling Granite Wash horizontal wells in 2011 which
equates to approximately 22 operated GW wells at an approximate net cost
of $82 million. In addition, Unit anticipates it will participate in
approximately 16 outside operated horizontal wells at an approximate net
cost of $14 million.

Unit’s Segno play, located primarily in Polk, Tyler and Hardin Counties,
Texas, continues to grow as the company expanded its prospect area to
the south by entering into a joint exploration agreement with a third
party for the use of a proprietary 3-D seismic survey covering
approximately 151 square miles. Under the exploration agreement Unit was
required to drill three Wilcox wells, which it did during 2010. One of
the wells resulted in a confirmed gas discovery that started selling gas
in late November at an initial rate of approximately 151 barrels of oil
per day, 310 barrels of NGLs per day, and 3.7 MMcf per day, or an
equivalent rate of approximately 6.4 MMcfe per day. The other two wells
are potential gas discoveries pending further testing after the pipeline
connecting the wells is finished, which should occur in late first
quarter 2011. For 2010, Unit operated and completed 22 wells at an
average working interest of 62.5% and a 77% success rate. The overall
production from Unit’s Segno area for December 2010 averaged 1,141
barrels of oil per day, 1,371 barrels of NGLs per day and 16.6 MMcf per
day, or an equivalent rate of 31.7 MMcfe per day. The average completed
gross well cost was approximately $3.4 million per well for 2010 wells.
For 2011, Unit plans to drill approximately 20 gross wells with an
approximate working interest of 80% for an estimated $54 million. Unit
owns approximately 57,000 gross and 48,000 net acres in the Segno play.

In the Bakken play located in North Dakota, Unit participated in 20
wells in 2010 with a 100% success rate at an average working interest of
11% and a total cost of approximately $18.5 million. The finding cost
for the 2010 wells averaged $21.24 per barrel of oil equivalent with a
total per well cost of approximately $7.9 million, which equates to
gross reserves of approximately 500 thousand barrels of oil equivalent
per well. For 2011, Unit anticipates participating in approximately 25
gross wells with an average working interest of 15% at a total cost of
approximately $30 million. Unit owns approximately 12,750 net acres in
the play and anticipates two to three rigs drilling on its North Dakota
Bakken leasehold during 2011.

Contract Drilling Segment Information

Unit’s contract drilling segment has recently entered into an agreement
to build an additional new 1,500 horsepower, diesel-electric drilling
rig. This brings to five the number of new drilling rigs that Unit will
add to its fleet in 2011. All five rigs are under long-term contracts
and are 1,500 horsepower, diesel-electric drilling rigs. Two of the
drilling rigs are anticipated to be completed during the first quarter
of 2011 and the remaining three sometime during the third quarter of
2011. On completion of these new drilling rigs, this segment will have
126 drilling rigs in its fleet.

The average number of drilling rigs used in the fourth quarter of 2010
was 70.9, an increase of 8% and 93% over the third quarter of 2010 and
the fourth quarter of 2009, respectively.

Mid-Stream Segment Information

Unit’s mid-stream segment continues to increase total throughput
volumes, as well as processed volumes and liquids sales. During the
fourth quarter, this segment completed the installation and start-up of
the Lone Tree Gas Processing Plant, located in Hemphill County, Texas.
The Lone Tree Plant is a turbo expander plant with processing capacity
of 50 MMcf per day. The completion of the Lone Tree Plant increases the
capacity of the Hemphill Processing Complex to 100 MMcf per day, with
run rates expected at 75 to 80 MMcf per day by the middle of the second
quarter. Within the last seven years this complex has expanded to
include four processing plants and 130 miles of associated gathering
lines in the Granite Wash trend of Hemphill and Roberts Counties, Texas.

In addition to the activities in the mid-continent area, this segment is
also expanding operations into the Appalachian region. Currently, it is
constructing a 16 mile, 16″ pipeline and accompanying compressor station
in Preston County, West Virginia. On completion of this project, the
pipeline will be able to deliver up to 220 MMcf per day into Columbia
Gas transmission. This pipeline project is on schedule to be completed
by mid-2011. In addition to the Preston County construction project,
this segment is continuing to explore and evaluate possible development
projects in and around the Appalachian area.

Management Comments

Larry Pinkston, President and Chief Executive Officer of Unit
Corporation, said: “2010 had its challenges but ended with all three
segments having a very good fourth quarter. Our oil and natural gas
segment struggled during the first half of the year due primarily to the
unavailability of well completion services by third party suppliers.
During the third quarter, we were able to obtain these services so that
by the end of the year we had reduced the unusually large backlog of
well completions, especially in our Granite Wash and Marmaton plays.
Additionally, we have scheduled fracture stimulation services for all of
2011 for the wells we currently plan to drill in the Granite Wash and
Marmaton plays. Our 2010 proved oil and natural gas reserves increased
8% over 2009 with a notable 28% increase in our oil and NGLs reserves
which is consistent with our ongoing focus of conducting our exploration
efforts in oil or liquids rich areas like the Granite Wash, Marmaton and
Segno plays.”

“As demand for horizontal drilling increases in 2011, we will continue
to add new rigs to meet that demand, and we will continue to refurbish
and upgrade additional rigs in the fleet targeted toward horizontal
drilling activity. The five new rigs that we are adding to our fleet
under long-term contracts should result in good economic returns for
several years, and we have approximately 20 drilling rigs in our fleet
that are candidates for upgrades.”

“We anticipate that 2011 will be a good year for Unit and the industry.
Along with the drilling opportunities in our Marmaton, Segno, and
Granite Wash plays, and the increases in demand for our drilling rigs,
our mid-stream segment is growing with higher capacity systems and the
developing opportunities in the Marcellus basin.”

Fourth Quarter and Year-End 2010 Webcast

Unit will release its fourth quarter and year-end 2010 earnings and host
a conference call on Tuesday, February 22, 2011. The webcast will be
broadcast live over the Internet at 11:00 a.m. Eastern time at

Unit Corporation is a Tulsa-based, publicly held energy company engaged
through its subsidiaries in oil and natural gas exploration, production,
contract drilling and natural 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

This news release contains forward-looking statements within the meaning
of the private Securities Litigation Reform Act. All statements, other
than statements of historical facts, included in this release that
address activities, events or developments that the Company expects or
anticipates will or may occur in the future are forward-looking
statements. A number of risks and uncertainties could cause actual
results to differ materially from these statements, including the impact
that the current decline in wells being drilled will have on production
and drilling rig utilization, productive capabilities of the Company’s
wells, future demand for oil and natural gas, future drilling rig
utilization and dayrates, projected growth of the Company’s oil and
natural gas production, oil and gas reserve information, as well as the
ability to meet its future reserve replacement goals, anticipated gas
gathering and processing rates and throughput volumes, the prospective
capabilities of the reserves associated with the Company’s inventory of
future drilling sites, anticipated oil and natural gas prices, the
number of wells to be drilled by the Company’s oil and natural gas
segment, development, operational, implementation and opportunity risks,
possibility of future growth opportunities, and other factors described
from time to time in the Company’s publicly available SEC reports. The
Company assumes no obligation to update publicly such forward-looking
statements, whether as a result of new information, future events or

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

Unit Corporation
Unaudited Reconciliation of PV-10 to
Standard Measure

December 31, 2010

PV-10 is the estimated future net cash flows from proved reserves
discounted at an annual rate of 10 percent before giving effect to
income taxes. Standardized Measure is the after-tax estimated future
cash flows from proved reserves discounted at an annual rate of 10
percent, determined in accordance with GAAP. The company uses PV-10 as
one measure of the value of its proved reserves and to compare relative
values of proved reserves among exploration and production companies
without regard to income taxes. The company believes that securities
analysts and rating agencies use PV-10 in similar ways. The company’s
management believes PV-10 is a useful measure for comparison of proved
reserve values among companies because, unlike Standardized Measure, it
excludes future income taxes that often depend principally on the
characteristics of the owner of the reserves rather than on the nature,
location and quality of the reserves themselves. Below is a
reconciliation of PV-10 to Standardized Measure:

($ in billions)
PV-10 at December 31, 2010 $ 1.3
Discounted effect of income taxes (0.4 )
Standardized Measure at December 31, 2010 $ 0.9

Unit Corporation
David T. Merrill, 918-493-7700
Financial Officer & Treasurer