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Unit Corporation (UNT) today reported its financial and operational results for the second quarter of 2013. Highlights include:

  • Adjusted non-GAAP net income for the quarter was $48.8 million, or $1.01 per diluted share (see Non-GAAP Financial Measures below).
  • Total production for the quarter was 4.1 million barrels of oil equivalent (MMBoe), an increase of 23% over the second quarter of 2012.
  • Production guidance for 2013 is being increased to between 16.4 and 16.9 MMBoe.
  • Total liquids (oil and natural gas liquids) production for the quarter increased 23% over the comparable quarter of 2012.
  • Sold two idle 2,000 horsepower drilling rigs.
  • Mid-stream segment’s liquids volumes per day and gathered volumes per day increased by 21% and 20%, respectively, over the first quarter of 2013.
  • Mid-stream operating profit (as defined in the Selected Financial and Operational Highlights) for the quarter was $11.1 million, an increase of 39% over the first quarter of 2013.

Net income for the quarter was $59.0 million, or $1.22 per diluted share, compared to a loss of $19.3 million, or $0.40 per diluted share, for the second quarter of 2012. Net income included the effect of a $16.5 million ($10.2 million after tax) increase in earnings from the unrealized value of commodity derivatives. Without this increase, net income would have been $48.8 million, or $1.01 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the quarter were $340.4 million (48% oil and natural gas, 31% contract drilling, and 21% mid-stream), compared to $327.8 million (40% oil and natural gas, 45% contract drilling, and 15% mid-stream) for the second quarter of 2012.

Net income for the six months ended June 30, 2013 was $99.2 million, or $2.05 per diluted share, compared to $33.1 million, or $0.69 per diluted share, for the first six months of 2012. Net income for the first six months of 2013 included the effect of a $9.6 million ($5.9 million after tax) increase in earnings from the unrealized value of commodity derivatives. Without this increase, net income for the first six months of 2013 would have been $93.3 million, or $1.93 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the first six months of 2013 were $659.0 million (48% oil and natural gas, 32% contract drilling, and 20% mid-stream), compared to $661.8 million (40% oil and natural gas, 44% contract drilling, and 16% mid-stream) for the first six months of 2012.

OIL AND NATURAL GAS SEGMENT INFORMATION

Unit’s production results reflect its focus on drilling oil or natural gas liquids (NGLs) rich wells. Liquids production represented 44% of total equivalent production for the quarter. Total equivalent production for the quarter increased 23% over the second quarter of 2012 to 4.1 MMBoe, while total liquids production increased 23% over the comparable quarter of 2012. Liquids production has increased 144% since the first quarter of 2009 when Unit began focusing on increasing its liquids production. Second quarter 2013 oil production was 859,000 barrels, compared to 786,000 barrels for the same period of 2012, an increase of 9%. NGLs production for the quarter was 935,000 barrels, an increase of 39% when compared to 674,000 barrels for the same period of 2012. Natural gas production increased 23% to 13.9 billion cubic feet (Bcf) compared to 11.3 Bcf for the comparable quarter of 2012. Total production for the first six months of 2013 was 8.1 MMBoe.

Unit’s average natural gas price for the quarter increased 20% to $3.65 per thousand cubic feet (Mcf) compared to $3.03 per Mcf for the second quarter of 2012. Unit’s average oil price for the quarter increased 3% to $94.89 per barrel compared to $92.43 per barrel for the second quarter of 2012. Unit’s average NGLs price for the quarter was $30.32 per barrel compared to $32.34 per barrel for the second quarter of 2012, a decrease of 6%. For the first six months of 2013, Unit’s average natural gas price increased 9% to $3.47 per Mcf as compared to $3.19 per Mcf for the first six months of 2012. Unit’s average oil price for the first six months of 2013 was $95.05 per barrel compared to $94.04 per barrel during the first six months of 2012, a 1% increase. Unit’s average NGLs price for the first six months of 2013 was $32.47 per barrel compared to $35.53 per barrel during the first six months of 2012, a 9% decrease. All prices reflected in this paragraph include the effects of hedges.

For 2013, Unit has hedged 8,330 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 $97.94 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 at a comparable average NYMEX price of $3.65. The collar transaction was at a comparable average NYMEX floor price of $3.25 and ceiling price of $3.72.

For 2014, Unit has hedged 7,000 Bbls per day of its oil production and 50,000 MMBtu per day of natural gas production. Of the oil production, 3,000 Bbls per day is hedged with swaps and 4,000 Bbls per day is hedged with collars. The swap transactions were at an average price of $91.77. The collar transactions were at an average floor price of $90.00 and ceiling price of $96.08. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $4.24 per MMBtu.

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The following table illustrates Unit’s production and realized prices for the periods indicated:

2nd Qtr 13 1st Qtr 13 4th Qtr 12 3rd Qtr 12 2nd Qtr 12 1st Qtr 12 4th Qtr 11 3rd Qtr 11 2nd Qtr 11
Oil and NGL Production, MBbl 1,794.1 1,600.6 1,694.1 1,545.8 1,460.2 1,375.2 1,359.9 1,197.5 1,158.6
Natural Gas Production, Bcf 13.9 14.2 14.5 11.7 11.3 11.4 11.4 11.6 10.9
Production, MBoe 4,109 3,971 4,115 3,498 3,341 3,275 3,255 3,123 2,983
Production, MBoe/day 45.2 44.1 44.7 38.0 36.7 36.0 35.4 33.9 32.8
Realized Price, Boe (1) $ 39.10 $ 37.99 $ 39.56 $ 37.99 $ 38.49 $ 40.51 $ 42.65 $ 41.75 $ 42.23

(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.

The Wilcox play in southeast Texas continues to produce strong results with average daily production for the quarter increasing approximately 9% and 17% compared to the first quarter 2013 and the second quarter 2012, respectively. This increase was primarily the result of two new vertical well completions and several significant behind pipe recompletions in previously drilled wells. Unit anticipates this production momentum will continue into the third quarter. In the “Gilly” Lower Wilcox field, at the end of the second quarter the resource potential increased approximately 31% compared to year end to 302 gross Bcfe (220 net Bcfe), primarily because of data obtained from drilling and testing new wells in the field. Subsequent to the end of the second quarter, Unit drilled an additional well outside the known limits of existing production on the west side of the “Gilly” field that logged approximately 250 feet of potential pay. The well is scheduled to be tested during the third quarter and could result in another increase to the overall estimated resource potential for the field. Additional vertical field wells are planned later this year to further delineate the lateral extent of the field. Drilling operations have also started on Unit’s first horizontal Wilcox well located within the “Gilly” field. This well is targeting one of the lower pay sands at a vertical depth of approximately 14,500 feet with a projected 2,800 foot lateral. The location of the well is designed to penetrate and case off the majority of the shallower field pays for potential future production before drilling the horizontal part of the well. Results from the horizontal well are anticipated near the end of the third quarter. Approximately one mile north of the “Gilly” Field, Unit discovered a new productive fault block with the completion of two recent wells. Unit plans to drill a third well during the third quarter to further delineate the potential of the discovery. For the remainder of 2013, Unit is adding a second Unit rig in its Wilcox play which should result in a total of 12 to 14 gross wells drilled in this play for the year at a net cost of approximately $78 million.

In Unit’s Mississippian play in south central Kansas, the installation of the pipeline and processing infrastructure by Superior Pipeline is underway with an estimated completion in mid-August 2013. Unit resumed drilling in the prospect in late July and plans to work one or two Unit drilling rigs for the remainder of 2013. Since the initial well completion in this play in May 2012 through the end of the second quarter 2013, Unit has completed seven horizontal wells in the prospect area with five of the seven wells having sufficient production data to discuss results. The average 30 day initial production (IP) rate for the five wells is approximately 238 Boe per day and the preliminary reserve range is estimated at 125 MBoe to 180 MBoe comprising approximately 58% liquids. Average production for the second quarter was up 146% over the previous quarter. Unit has approximately 118,000 net acres in the Mississippian play and plans to spend approximately $40 million (net) drilling and completing approximately 13 gross wells during 2013. Unit has a 100% working interest in all seven of the completed horizontal wells.

In its Granite Wash (GW) play in the Texas Panhandle, Unit has four Unit rigs drilling and will potentially add a fifth Unit rig in August and a sixth Unit rig in October. For the first half of 2013, Unit had first sales on eight horizontal wells, having an average peak 30 day IP rate of 4.5 MMcfe per day at an average working interest of 96%. Subsequent to the second quarter, Unit has completed drilling operations on three GW horizontal wells and is drilling two GW horizontal wells on leasehold acquired from the recent Noble acquisition. Completion and first oil and gas sales for these wells is estimated to occur during the fourth quarter 2013. For 2013, Unit anticipates completing approximately 28 gross horizontal wells at an approximate net cost of $145 million.

In the Marmaton horizontal oil play in Beaver County, Oklahoma, Unit completed 23 wells through the second quarter of 2013 with an average working interest of 77%. The average 30 day peak rate for second quarter wells was approximately 350 Boe, which is in line with expectations. Average net daily production for the second quarter was approximately 3,800 barrels of oil equivalent per day which is an increase of approximately 22% as compared to the second quarter 2012. Development of the field is continuing on one well per 640 acre spacing. Unit has leases on approximately 115,000 net acres in this play with approximately 53% of the leasehold held by production. Unit anticipates continuing the two Unit rig program in this play which should result in approximately 46 gross wells being completed during 2013 at an approximate net cost of $105 million.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results from our exploration operations, and we are excited about our opportunities for growth. Production has grown during the second quarter of 2013 from the first quarter of 2013 due principally to our gradual ramp up in company operated drilling rigs. We are operating 11 drilling rigs and plan to add additional drilling rigs throughout 2013 depending on market conditions. Unit’s annual production guidance for 2013 is being increased to between 16.4 to 16.9 MMBoe, an increase of 15% to 19% over 2012.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the second quarter of 2013 was 65.2, a decrease of 15% from the second quarter of 2012, and a decrease of 2% from the first quarter of 2013. Per day drilling rig rates for the second quarter of 2013 averaged $19,601, a decrease of 3%, or $527, from the second quarter of 2012, and essentially unchanged from the first quarter of 2013. Average per day operating margin for the second quarter of 2013 was $7,597 (before elimination of intercompany drilling rig profit of $3.7 million). This compares to $11,130 (before elimination of intercompany drilling rig profit of $4.7 million) for the second quarter of 2012, a decrease of 32%, or $3,533. As compared to the first quarter of 2013 ($7,534 before elimination of intercompany drilling rig profit of $3.4 million), second quarter 2013 operating margin increased 1% or $63 (in each case regarding eliminating intercompany drilling rig profit see Non-GAAP Financial Measures below). For the second quarter of 2012 average operating margins included early termination fees of approximately $2,188 per day from the cancellation of certain long-term contracts.

For the first six months of 2013, Unit averaged 65.8 drilling rigs working, a decrease of 17% from 79.1 drilling rigs working during the first six months of 2012. Average per day operating margin for the first six months of 2013 was $7,565 (before elimination of intercompany drilling rig profit of $7.1 million) as compared to $10,246 (before elimination of intercompany drilling rig profit of $9.0 million) for the first six months of 2012, a decrease of 26% (in each case regarding eliminating intercompany drilling rig profit see Non-GAAP Financial Measures below). For the first six months of 2012 average operating margins included early termination fees of approximately $1,109 per day from the cancellation of certain long-term contracts.

Larry Pinkston said: “Drilling rig demand has been fairly flat during the first six months of 2013. Operators are continuing to focus on shallower oil plays and liquids rich plays which provide the opportunity to put more of our 750 to 1,000 horsepower drilling rigs to work. Almost all of our drilling rigs working today are drilling for oil or NGLs. Recently, we sold two 2,000 horsepower drilling rigs, bringing our fleet’s total to 125. Of the 125 drilling rigs, we have 65 under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 27 of those 65 drilling rigs. Of these contracts, 13 are up for renewal during the third quarter of 2013, three during the fourth quarter of 2013, and 11 in 2014 and beyond. We are constructing a new prototype 1,500 horsepower AC electric drilling rig of proprietary design. The drilling rig is expected to be operational in the fourth quarter of 2013 and will operate initially for our oil and natural gas segment.”

The following table illustrates Unit’s drilling rig count at the end of each period and average utilization rate during the period:

2nd Qtr 13 1st Qtr 13 4th Qtr 12 3rd Qtr 12 2nd Qtr 12 1st Qtr 12 4th Qtr 11 3rd Qtr 11 2nd Qtr 11
Rigs 126 127 127 127 128 127 127 126 123
Utilization 51% 52% 50% 58% 60% 64% 65% 63% 60%

MID-STREAM SEGMENT INFORMATION

Second quarter of 2013 per day gathered volumes were 326,039 Mcf, an increase of 24% over the second quarter of 2012. Per day liquids sold and processed volumes decreased 19% and 4%, respectively, as compared to the second quarter of 2012. Compared to the first quarter of 2013, gathered volumes per day, liquids sold volumes per day, and processed volumes per day increased 20%, 21% and 6%, respectively. Operating profit (as defined in the Selected Financial and Operational Highlights) for the second quarter of 2013 was $11.1 million, an increase of 50% over the second quarter of 2012 and an increase of 39% over the first quarter of 2013.

The following table illustrates certain results from this segment’s operations for the periods indicated:

2nd Qtr 13 1st Qtr 13 4th Qtr 12 3rd Qtr 12 2nd Qtr 12 1st Qtr 12 4th Qtr 11 3rd Qtr 11 2nd Qtr 11
Gas gathered
Mcf/day
326,039 272,831 279,990 241,271 262,269 217,404 222,436 198,625 168,030
Gas processed
Mcf/day
138,130 129,857 131,570 134,907 144,257 125,231 126,628 104,351 71,561
Liquids soldGallons/day 508,189 420,291 441,973 576,889 629,350 522,829 511,410 449,604 356,484

Larry Pinkston said: “In the Mississippian play in north central Oklahoma, our Bellmon system consists of approximately 136 miles of pipe. In the first quarter of 2013, we completed the installation of a second processing plant at the Bellmon facility, a 30 MMcf per day cryogenic plant. Due to increasing volumes, we are installing an additional 60 MMcf per day processing plant at our Bellmon facility expected to be operational in the fourth quarter of 2013. At our Hemphill facility in Hemphill County, Texas, we now can process 135 MMcf per day of our own and third party Granite Wash natural gas production after relocating two processing plants from Hemphill to the new Reno facility. We are also completing two pipeline extension projects for a total cost of approximately $5.7 million, which will allow us to connect additional production from our oil and natural gas segment to this system. In Reno County, Kansas, we are constructing a new gathering system and processing facility. This system will comprise 35 miles of gathering pipeline and two processing plants which were relocated from our Hemphill facility, a 5 MMcf per day refrigeration plant and a 20 MMcf per day turbo expander plant. At this facility, we are currently only gathering gas but are in the process of installing two processing plants that are expected to be operational in the third quarter of 2013.

“In the Appalachian area, we are continuing to develop our Pittsburgh Mills gathering system in Allegheny County, Pennsylvania. We have completed the 1st phase of this project which comprises approximately 14 miles of gathering pipeline and related compressor station in which we have installed three compressors. We have 19 wells connected to this system with gathered volume of approximately 68 MMcf per day.”

FINANCIAL INFORMATION

Unit ended the second quarter with long-term debt of $715.5 million ($645.5 million of senior subordinated notes and $70.0 million under its credit agreement), and a debt to capitalization ratio of 26%. Under its credit agreement, the amount available for Unit to borrow is the lesser of the amount Unit elects as the commitment amount ($500 million) or the value of its borrowing base as determined by the lenders ($800 million), but in either event not to exceed $900 million.

MANAGEMENT COMMENT

Larry Pinkston said: “We are pleased with the performance of all three segments and we are excited about continued growth opportunities for 2013. Each segment is moving forward on key initiatives which should create additional shareholder value for years to come. We continue to maintain a conservative financial profile. We are well positioned for continued growth and to take advantage of new opportunities that may arise.”

WEBCAST

Unit will webcast its second quarter earnings conference call live over the Internet on August 6, 2013 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 on the New York Stock Exchange under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.

FORWARD-LOOKING STATEMENT

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. Several risks and uncertainties could cause actual results to differ materially from these statements, including the 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, and 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 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 because of new information, future events or otherwise.

Unit CorporationSelected Financial and Operations Highlights

(In thousands except per share and operations data)

Three Months Ended Six Months Ended
June 30, June 30,
2013 2012 2013 2012
Statement of Operations:
Revenues:
Oil and natural gas $ 164,799 $ 131,166 $ 318,408 $ 266,931
Contract drilling 105,005 146,872 212,533 287,778
Gas gathering and processing 70,617 49,747 128,012 107,042
Total revenues 340,421 327,785 658,953 661,751
Expenses:
Oil and natural gas:
Operating costs 44,994 33,279 88,032 68,888
Depreciation, depletion, and amortization 55,335 57,153 107,318 109,350
Impairment of oil and natural gas properties 115,874 115,874
Contract drilling:
Operating costs 63,590 74,819 129,592 150,992
Depreciation 17,908 21,238 35,168 42,566
Gas gathering and processing:
Operating costs 59,557 42,363 108,967 89,976
Depreciation and amortization 8,214 5,312 15,370 10,446
General and administrative 9,679 8,376 18,352 15,380
Gain on disposition of assets (3,483 ) (651 ) (3,399 ) (1,239 )
Total operating expenses 255,794 357,763 499,400 602,233
Income (loss) from operations 84,627 (29,978 ) 159,553 59,518
Other income (expense):
Interest, net (4,591 ) (2,542 ) (8,152 ) (4,368 )
Gain (loss) on derivatives 16,344 1,387 10,420 (606 )
Other (91 ) 69 (157 ) (64 )
Total other income (expense) 11,662 (1,086 ) 2,111 (5,038 )
Income (loss) before income taxes 96,289 (31,064 ) 161,664 54,480
Income tax expense (benefit):
Current 2,117 (2,066 ) 4,634 (2,066 )
Deferred 35,165 (9,696 ) 57,817 23,409
Total income taxes 37,282 (11,762 ) 62,451 21,343
Net income (loss) $ 59,007 $ (19,302 ) $ 99,213 $ 33,137
Net income (loss) per common share:
Basic $ 1.22 $ (0.40 ) $ 2.06 $ 0.69
Diluted $ 1.22 $ (0.40 ) $ 2.05 $ 0.69
Weighted average shares outstanding:
Basic 48,208 47,906 48,162 47,868
Diluted 48,506 47,906 48,491 48,113
June 30, December 31,
2013 2012
Balance Sheet Data:
Current assets $ 199,669 $ 195,644
Total assets $ 3,899,524 $ 3,761,120
Current liabilities $ 189,931 $ 207,139
Long-term debt $ 715,474 $ 716,359
Other long-term liabilities $ 160,907 $ 167,545
Deferred income taxes $ 753,663 $ 695,776
Shareholders’ equity $ 2,079,549 $ 1,974,301
Six Months Ended June 30,
2013 2012
Statement of Cash Flows Data:
Cash flow from operations before changes
in operating assets and liabilities (1) $ 317,098 $ 345,123
Net change in operating assets and liabilities 790 (30,091 )
Net cash provided by operating activities $ 317,888 $ 315,032
Net cash used in investing activities $ (322,471 ) $ (367,608 )
Net cash provided by financing activities $ 4,650 $ 52,826
Three Months Ended Six Months Ended
June 30, June 30,
2013 2012 2013 2012
Oil and Natural Gas Operations Data:
Production:
Oil – MBbls 859 786 1,656 1,506
Natural Gas Liquids – MBbls 935 674 1,739 1,330
Natural Gas – MMcf 13,887 11,287 28,107 22,688
Average Prices:
Oil price per barrel received $ 94.89 $ 92.43 $ 95.05 $ 94.04
Oil price per barrel received, excluding hedges $ 91.58 $ 89.38 $ 91.75 $ 94.53
NGLs price per barrel received $ 30.32 $ 32.34 $ 32.47 $ 35.53
NGLs price per barrel received, excluding hedges $ 30.32 $ 31.12 $ 32.47 $ 34.19
Natural gas price per Mcf received $ 3.65 $ 3.03 $ 3.47 $ 3.19
Natural gas price per Mcf received, excluding hedges $ 3.93 $ 1.91 $ 3.53 $ 2.18
Operating profit before depreciation, depletion, amortization, and impairment (2) ($MM) $ 119.8 $ 97.9 $ 230.4 $ 198.0
Contract Drilling Operations Data:
Rigs utilized 65.2 76.7 65.8 79.1
Operating margins (2) 39 % 49 % 39 % 48 %
Operating profit before depreciation (2) ($MM) $ 41.4 $ 72.1 $ 82.9 $ 136.8
Mid-Stream Operations Data:
Gas gathering – Mcf/day 326,039 262,269 299,582 239,837
Gas processing – Mcf/day 138,130 144,257 134,016 134,744
Liquids sold – Gallons/day 508,189 629,350 464,483 576,089
Operating profit before depreciation and amortization (2) ($MM) $ 11.1 $ 7.4 $ 19.0 $ 17.1

(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 gain on disposition of assets. 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 cash flow from operations before changes in operating assets and liabilities, our drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit, and net income and earnings per share excluding the effect of the unrealized value of commodity derivatives and the impairment of oil and natural gas properties.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and six months ended June 30, 2013 and 2012. Non-GAAP financial measures should not be considered by themselves or a substitute for our results reported in accordance with GAAP.

Unit CorporationReconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
Six Months EndedJune 30,
2013 2012
(In thousands)
Net cash provided by operating activities $ 317,888 $ 315,032
Net change in operating assets and liabilities (790 ) 30,091
Cash flow from operations before changes in operating assets and liabilities $ 317,098 $ 345,123

________________

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 Six Months Ended
March 31, June 30, June 30,
2013 2013 2012 2013 2012
(In thousands except operating days and operating margins)
Contract drilling revenue $ 107,528 $ 105,005 $ 146,872 $ 212,533 $ 287,778
Contract drilling operating cost 66,002 63,590 74,819 129,592 150,992
Operating profit from contract drilling 41,526 41,415 72,053 82,941 136,786
Add:
Elimination of intercompany rig profit 3,409 3,686 4,669 7,095 8,953
Operating profit from contract drilling before elimination of intercompany rig profit 44,935 45,101 76,722 90,036 145,739
Contract drilling operating days 5,964 5,937 6,893 11,901 14,224
Average daily operating margin before elimination of intercompany rig profit $ 7,534 $ 7,597 $ 11,130 $ 7,565 $ 10,246

________________

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 CorporationReconciliation of Net Income (Loss) and Diluted Earnings (Loss) per Share

Excluding the Effect of the Unrealized Value of Commodity Derivatives

And the Impairment of Oil and Natural Gas Properties

Three Months Ended Six Months Ended
June 30, June 30,
2013 2012 2013 2012
(In thousands except earnings per share)
Net income excluding the unrealized value of commodity derivatives and impairment of oil and natural gas properties:
Net income (loss) $ 59,007 $ (19,302 ) $ 99,213 $ 33,137
Impairment of oil and natural gas properties 72,132 72,132
Unrealized value of commodity derivatives (net of income tax) (10,163 ) (850 ) (5,880 ) 372
Net income excluding the unrealized value of commodity derivatives and impairment of oil and natural gas properties $ 48,844 $ 51,980 $ 93,333 $ 105,641
Diluted earnings per share excluding the unrealized value of commodity derivatives and Impairment of oil and natural gas properties:
Diluted earnings (loss) per share $ 1.22 $ (0.40 ) $ 2.05 $ 0.69
Impairment of oil and natural gas properties 1.50 1.50
Diluted earnings per share from the unrealized value of commodity derivatives (0.21 ) (0.02 ) (0.12 ) 0.01
Diluted earnings per share excluding the unrealized value of commodity derivatives and impairment of oil and natural gas properties $ 1.01 $ 1.08 $ 1.93 $ 2.20

________________

We have included the net income excluding the unrealized value of commodity derivatives and impairment of oil and natural gas properties and diluted earnings per share excluding the unrealized value of commodity derivatives and 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.

Contact:
Unit Corporation
Michael D. Earl, 918-493-7700
Vice President, Investor Relations
www.unitcorp.com

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