Unit Corporation Announces 2012 Capital Expenditure Budget, 2012 Production Guidance and 2011 Total Proved Reserves

Unit Corporation announced its initial 2012 capital expenditure budget, 2012 production guidance and 2011 total proved oil and natural gas reserves, as well as certain operational updates for each of its three business segments. This information is unaudited and preliminary and is subject to change. Audited final results will be reported in Unit’s Schedule 10-K for the year ended December 31, 2011.

2012 Capital Expenditure Budget

The 2012 capital expenditures budget for all of Unit’s business segments is $801 million, an increase of 6% over estimated 2011 capital expenditures, excluding acquisitions. Of this amount, $457 million is budgeted for its oil and natural gas segment, which includes $385 million for drilling and completion activities, an 11% decrease over estimated 2011 capital expenditures, $120 million for its contract drilling segment, a 27% decrease over estimated 2011 capital expenditures, and $224 million for its mid-stream segment, a 182% increase over estimated 2011 capital expenditures.

Unit’s 2012 capital expenditures budget is based on prices for oil and natural gas averaging $90.00 per barrel and $3.50 per thousand cubic feet (Mcf) for the year. This budget is subject to possible adjustments for various reasons including changes in commodity prices and industry conditions. Funding for the 2012 capital expenditures budget will come 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 2011, this segment achieved, in part, the following results:

• Year end proved reserves increased 12% to 116.0 million barrels of oil equivalents (MMBoe), of which oil and NGLs reserves increased 16% and 37%, respectively.
• Total production increased 23% to 12.1 MMBoe, of which oil and NGLs production increased 65% and 45%, respectively.
• Replaced 202% of its 2011 production with new reserve additions, of which 141% was through the drill bit.

• 2011 Total Proved Oil and Natural Gas Reserves
• Total proved oil and natural gas reserves at December 31, 2011 were 116.0 MMBoe, consisting of 20.3 million barrels (MMbls) of oil, 22.1 MMbls of natural gas liquids (NGLs) and 442.1 billion cubic feet (Bcf) of natural gas. This represents a 12% increase over 2010 year-end total proved reserves. Between 2011 and 2010, Unit’s oil and NGLs reserves increased 16% and 37%, respectively, while its natural gas reserves increased 5%. The significant increase in Unit’s oil and NGLs reserves at December 31, 2011 is the result of the strategy implemented by Unit at the beginning of 2009 to focus on oil or liquids rich prospects. Eighty-one percent of Unit’s proved oil and natural gas reserves are “proved developed,” with the remaining 19% comprising “proved undeveloped” reserves.
• Ryder Scott Company, L.P. (Ryder Scott), an independent reserve engineering firm, audited Unit’s proved reserves. Their audit covered properties which accounted for 84% of the anticipated future net cash flow, before income taxes, based on the company’s total 2011 year end proved reserves.
• The following details the changes to Unit’s proved oil and natural gas reserves during 2011:

The estimated future net cash flow from Unit’s December 31, 2011 total proved oil and natural gas reserves, before income taxes, is $3.0 billion. The present value of those reserves (before income taxes and discounted at 10% (PV-10)) is approximately $1.6 billion, a 23% increase over 2010. These value estimates were made using the 12-month unweighted arithmetic average of the first day of the month price for the period January 1, 2011 through December 31, 2011. The resulting prices used (unescalated) were $96.19 per barrel of oil, $61.78 per barrel of NGLs, and $4.12 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. 2011 Production and 2012 Production Guidance

Production during the fourth quarter of 2011 was 744,000 barrels of oil, 616,000 barrels of NGLs and 11.4 Bcf of natural gas, or 3.3 MMBoe, an increase of 4% and 21% over the third quarter of 2011 and the fourth quarter of 2010, respectively. Total production for 2011 was 12.1 MMBoe, an increase of 23% from the 9.9 MMBoe produced in 2010, and included an increase in oil and NGLs production of 55%.

For 2012, Unit’s preliminary annual production guidance is 13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011. This estimate is subject to change depending on a number of factors that may come into play during 2012.

Operational Updates

During 2011, Unit drilled 34 wells with an average working interest of 87% in its Marmaton horizontal oil play located in Beaver County, Oklahoma. The initial 30-day average production rate for the 34 wells ranged from 20 barrels of oil equivalent (Boe) per day to 930 Boe per day with an average rate of 308 Boe per day. The average ultimate recovery for a Marmaton horizontal well is estimated to be 130 MBoe, which is comprised of approximately 78% oil, 14% NGLs and 8% natural gas. The average completed well cost is approximately $2.7 million. The net production from Unit’s Marmaton operated wells for the fourth quarter 2011 averaged 2,295 barrels of oil per day, 321 barrels of NGLs per day, and 1,077 Mcf per day, an increase of 46% over the third quarter 2011 and a 176% increase over the fourth quarter 2010. For 2012, 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 $61 million to $71 million. Unit plans to drill its first 9,000’ extended lateral in this play during the first quarter of 2012 for an estimated cost of $4.2 million. The average lateral length drilled to date is 4,100 feet. Unit currently has leases on approximately 92,262 net acres in this play.

In its Granite Wash (GW) play located in the Texas Panhandle, Unit drilled and operated 16 horizontal wells with an average working interest of 76%. The 30-day average production rate for the 16 wells was 6.8 MMcfe per day. The GW laterals completed in 2011 targeted six different GW sands with 44% of the laterals drilled in the GW “B” interval. The average ultimate recovery for a GW horizontal well is estimated to be 4.6 Bcfe, which is comprised of 13% oil, 37% NGLs and 50% natural gas. The average completed well cost is approximately $5.5 million. The net production from Unit’s GW operated wells for the fourth quarter 2011 averaged 1,136 barrels of oil per day, 3,065 barrels of NGLs per day and 24.8 MMcf per day, or an equivalent rate of 50.5 MMcfe per day, an increase of 2% over the third quarter 2011 and a 59% increase over the fourth quarter 2010. Unit expects to work three to four Unit drilling rigs drilling horizontal wells in 2012 which equates to approximately 20 operated GW wells with an approximate net cost of $90 million.

Unit’s Wilcox play, located primarily in Polk, Tyler and Hardin Counties, Texas, continues to grow. For 2011, Unit operated and completed 17 wells with an average working interest of 97%. The net production from this area for the fourth quarter 2011 averaged 1,562 barrels of oil per day, 1,486 barrels of NGLs per day and 24.5 MMcf per day, or an equivalent rate of 42.7 MMcfe per day, an increase of 34% from the fourth quarter of 2010. For 2012, Unit plans to drill approximately 15 gross wells with an approximate working interest of 87% for an estimated cost of $41 million. Unit holds approximately 26,000 net leasehold acres in the Wilcox play. Unit has entered into a development agreement covering approximately 47,000 net mineral acres and has acquired lease options covering approximately 82,000 net mineral acres in the expanded area.

In the Bakken play located in North Dakota, Unit participated in 17 wells in 2011 at an average working interest of 11% and a total net cost of approximately $18 million. The average ultimate recovery for a Bakken horizontal well is estimated to be 662 MBoe. The net production from Unit’s Bakken play for the fourth quarter 2011 averaged approximately 831 barrels of oil per day and 977 Mcf per day, an increase of 42% from the fourth quarter of 2010. For 2012, Unit anticipates participating in approximately 20 gross wells with an average working interest of 10% to 15% at a total net cost of approximately $30 million. Unit owns approximately 13,400 net acres in the play and anticipates two to three rigs drilling on its North Dakota Bakken leasehold during 2012.

Unit has recently acquired approximately 60,000 net acres located primarily in south central Kansas in the developing Mississippian play. The current plans are to drill three to four horizontal wells in the next six months and evaluate the results before planning any further drilling in this play.