Crude Oil ( ) Brent Crude ( ) Natural Gas ( ) S&P 500 ( ) PHLX Oil ( )
Current UNT Stock Info

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:

3rd Qtr 12 2nd Qtr 12 1st Qtr 12 4th Qtr 11 3rd Qtr 11 2nd Qtr 11 1st Qtr 11 4th Qtr 10 3rd 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:

3rd Qtr 12 2nd Qtr 12 1st Qtr 12 4th Qtr 11 3rd Qtr 11 2nd Qtr 11 1st Qtr 11 4th Qtr 10 3rd 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:

3rd Qtr 12 2nd Qtr 12 1st Qtr 12 4th Qtr 11 3rd Qtr 11 2nd Qtr 11 1st Qtr 11 4th Qtr 10 3rd 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 tohttp://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 CorporationSelected 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 CorporationReconciliation of Net Income and Diluted Earnings per ShareExcluding 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 CorporationReconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
Nine Months EndedSeptember 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 CorporationReconciliation 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

 

© Business Wire 2012

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.