UNIT CORPORATION ANNOUNCES 2012 CAPITAL EXPENDITURE BUDGET,
2012 PRODUCTION GUIDANCE AND 2011 TOTAL PROVED RESERVES
AS WELL AS SEGMENT OPERATIONS UPDATES
Tulsa, Oklahoma . . . Unit Corporation (NYSE – UNT) announced today 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:
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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.
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Total production increased 23% to 12.1 MMBoe, of which oil and NGLs production increased 65% and 45%, respectively.
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Replaced 202% of its 2011 production with new reserve additions, of which 141% was through the drill bit.
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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:
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Oil and NGLs
(MMbls)
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Natural Gas
(Bcf)
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Proved Reserves
(MMBoe)
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Proved Reserves, at December 31, 2010
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33.6
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420.5
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103.7
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Revisions of previous estimates
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2.5
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(30.5
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(2.6
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Extensions, discoveries and other additions
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10.4
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55.4
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19.6
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Purchases of minerals in place
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0.6
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40.8
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7.4
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Production
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(4.8
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(44.1
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(12.1
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Proved Reserves, at December 31, 2011
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42.3
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442.1
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116.0
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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.
Contract Drilling Segment Information
Unit’s contract drilling segment has recently entered into an agreement to build a new 1,500 horsepower, diesel-electric drilling rig to be deployed to North Dakota. The drilling rig will be under a long-term contract and should be completed during the second quarter of 2012. Subsequent to year-end, we sold an idle 600 horsepower mechanical drilling rig to an
unaffiliated third party. On completion of the new drilling rig, this segment will have 128 drilling rigs in its fleet.
The average number of drilling rigs used in the fourth quarter of 2011 was 82.1, an increase of 4% and 16% over the third quarter of 2011 and the fourth quarter of 2010, respectively.
Unit will continue to upgrade certain of its existing drilling rigs during 2012. This work will include new engines, SCR houses, top drives, mud systems, and skidding systems. Most of the upgrades will be on 1,000 horsepower drilling rigs in order that the drilling rigs will fit growing operators’ demands in the shallower horizontal plays which are gaining momentum.
Mid-Stream Segment Information
Unit’s mid-stream segment continues to be very active in several key producing areas and is continuing to increase total throughput volumes. This segment’s Hemphill County facility in Texas is currently processing approximately 100 MMcf per day. Due to the continued high level of activity around the Hemphill facility, this segment will be installing an additional 45 MMcf per day gas processing plant which will increase this facility’s processing capacity to approximately 160 MMcf per day. This new plant should be completed during the second quarter of 2012.
At its Cashion facility, this segment is continuing to connect new wells to the system as well as installing a larger, more efficient gas processing plant. The installation of the new 25 MMcf per day high efficiency turbo-expander processing plant is scheduled to be operational during the second quarter of 2012.
This segment is also very active in the Mississippian play in north central Oklahoma. It completed construction of a new gathering system and gas processing plant in Grant County, Oklahoma during the fourth quarter of 2011. This system consists of approximately seven miles of gathering pipeline and a gas processing plant. Also in this area, it has begun construction of another gathering system and processing plant in Noble and Kay counties in Oklahoma. This
system will initially consist of approximately 10 miles of 12” and 16” pipe with a 30 MMcf per day gas processing plant.
Along with the activities in the mid-continent area, this segment is continuing to expand operations in the Appalachian region. In the fourth quarter of 2011, it completed construction of a 16 mile, 16” pipeline and accompanying compressor station in Preston County, West Virginia. This system is currently flowing approximately 6 MMcf per day. In addition to the Preston County gathering system, it has begun construction of another gathering facility in Allegheny and Butler counties, Pennsylvania. The first phase of this project consists of approximately seven miles of gathering pipeline and a compressor station. The first well has been connected to this system and is currently flowing approximately 5 MMcf per day into a third party transmission line.
Management Comments
Larry Pinkston, President and Chief Executive Officer of Unit Corporation, said: “2011 was a good year for all three of our business segments. We continued our focus of conducting our exploration efforts in oil or liquids rich areas like the Granite Wash, Marmaton and Wilcox plays. As a result, our 2011 proved oil and natural gas reserves increased 12% over 2010 with a notable 26% increase in our oil and NGLs reserves. Since implementing our focus on oil or liquids rich prospects at the beginning of 2009, our oil and NGLs reserves increased 113% while our total proved oil and natural gas reserves increased 22%.”
“If demand for horizontal drilling continues to increase in 2012, we will continue to add new drilling rigs to meet that demand, and we will continue to refurbish and upgrade existing drilling rigs in our fleet targeted towards that drilling activity. We have approximately 10 drilling rigs in our fleet that are candidates for upgrades. During 2011 and into January 2012, we added seven new drilling rigs to our fleet under long-term contracts, and we will add an additional drilling rig to our fleet during the second quarter of 2012. These drilling rigs should result in good economic returns for several years.”
“We look forward to 2012 and anticipate that it will be a good year for Unit. The Marmaton, Wilcox, Bakken, Granite Wash, and Mississippian plays should all provide good opportunities for our exploration segment. The demand for drilling rigs remains strong, while
our mid-stream segment is growing with the addition of higher capacity systems and developing opportunities in the Marcellus and Mississippian plays.”
“While we enter 2012 with good opportunities and plans for growth in all three business segments, we are monitoring the potential impacts that current low natural gas prices may have on our operations as well as our customers. In response to these current natural gas prices we may act to curtail up to 20 MMcf per day, or 16%, of our current daily natural gas production, or 9% of our total equivalent production. Any curtailment could result in subsequent changes to our 2012 preliminary production guidance, depending on the amount of the curtailment and how long we elect to curtail our production. Changing commodity prices, including any reductions in current oil and NGLs prices, may also result in modifications to our 2012 capital expenditure budget; however, decisions on any changes are not anticipated until after the first quarter of 2012. As we monitor natural gas prices, we will remain focused on the opportunities each of our business segments have for high-return projects. Our strong financial position provides us with confidence and flexibility as we continue to focus on creating value for our shareholders.”
Fourth Quarter and Year-End 2011 Webcast
Unit will release its fourth quarter and year-end 2011 earnings and host a conference call on Tuesday, February 21, 2012. The webcast will be broadcast live over the Internet at 11:00 a.m. Eastern time at http://www.unitcorp.com.
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 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 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 otherwise.
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.
Unit Corporation
Unaudited Reconciliation of PV-10 to Standard Measure
December 31, 2011
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:
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2011
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($ in billions)
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PV-10 at December 31, 2011
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$ 1.6
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Discounted effect of income taxes
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(0.5)
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Standardized Measure at December 31, 2011
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$ 1.1
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