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| 8-K - FORM 8-K - UNIT CORP | form8kyearendreserves.htm |
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news
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UNIT CORPORATION
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7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136
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Telephone 918 493-7700, Fax 918 493-7711
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Contact:
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David T. Merrill
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Chief Financial Officer & Treasurer
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(918) 493-7700
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For Immediate Release…
February 9, 2011
UNIT CORPORATION ANNOUNCES 2011 CAPITAL EXPENDITURE BUDGET,
2010 TOTAL PROVED RESERVES
AS WELL AS SEGMENT OPERATIONS UPDATES
Tulsa, Oklahoma . . . 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 million 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:
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Year end proved reserves of 622.2 billion cubic feet equivalents (Bcfe).
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Oil and natural gas production of 59.2 Bcfe.
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Replaced 176% of its 2010 production, with 158% through the drill bit.
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2010 Total Proved Oil and Natural Gas Reserves
Total proved oil and natural gas 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” reserves.
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:
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Oil and NGLs
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Natural Gas
(Bcf)
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Proved Reserves
(Bcfe)
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Proved Reserves, at December 31, 2009
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26.3
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419.1
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577.0
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Revisions of previous estimates
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(1.1)
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(24.9)
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(31.6)
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Extensions, discoveries and other additions
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10.0
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65.4
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125.3
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Purchases of minerals in place
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1.5
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1.7
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10.7
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Production
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(3.1)
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(40.8)
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(59.2)
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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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622.2
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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 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, 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:
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2010
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($ in billions)
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PV-10 at December 31, 2010
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$ 1.3
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Discounted effect of income taxes
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(0.4)
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Standardized Measure at December 31, 2010
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$ 0.9
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