Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - UNIT CORP | form8k02222011.htm |
|
News
|
UNIT CORPORATION
|
|
7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136
|
|
|
Telephone 918 493-7700, Fax 918 493-7714
|
|
Contact:
|
David T. Merrill
|
|
Chief Financial Officer
|
|
|
and Treasurer
|
|
|
(918) 493-7700
www.unitcorp.com
|
For Immediate Release…
February 22, 2011
UNIT CORPORATION REPORTS 2010 FOURTH QUARTER AND YEAR END RESULTS
Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) reported net income of $43.7 million, or $0.92 per diluted share, for the three months ended December 31, 2010. For the same period in 2009, net income was $28.5 million, or $0.60 per diluted share. Total revenues for the fourth quarter of 2010 were $252.6 million (39% contract drilling, 45% oil and natural gas, and 16% mid-stream), compared to $177.3 million (27% contract drilling, 51% oil and natural gas, and 21% mid-stream) for the fourth quarter of 2009.
For all of 2010, Unit reported net income of $146.5 million, or $3.09 per diluted share. For the same period in 2009, Unit reported a net loss of $55.5 million, or $1.18 per diluted share. The 2009 results included a noncash ceiling test write down of $281.2 million ($175.1 million after tax, or $3.70 per diluted share). The ceiling test write down reduced the carrying value of Unit's oil and natural gas properties and was required because of significantly lower commodity prices existing at the end of the first quarter 2009. Without the ceiling test write down, net income for 2009 would have been $119.6 million, or $2.52 per diluted share (see Non-GAAP Financial Measures below).
Total revenues for all of 2010 were $881.8 million (36% contract drilling, 45% oil and natural gas, and 18% mid-stream), compared to $709.9 million (33% contract drilling, 50% oil and natural gas, and 15% mid-stream) for the same period in 2009.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the fourth quarter of 2010 was 70.9, an increase of 93% over the fourth quarter of 2009, and an increase of 8% over the third quarter of 2010.
Per day drilling rig rates for the fourth quarter of 2010 averaged $16,570, up 13% (or $1,862) from the fourth quarter of 2009, and up 5% (or $756) from the third quarter of 2010.
Average per day operating margin for the fourth quarter of 2010 was $7,559 (before elimination of intercompany drilling rig profit of $4.4 million). This compares to $5,268 (before elimination of intercompany drilling rig profit and bad debt expense of $0.4 million) for the fourth quarter of 2009, an increase of 44%, or $2,292. As compared to the third quarter of 2010 ($7,056 before elimination of intercompany drilling rig profit of $2.9 million) fourth quarter 2010 operating margin increased 7% or $504 - in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below. Included in the average operating margin amount for the fourth quarter of 2010 and 2009 was a per day amount of $31 and $619 for early termination fees resulting from the cancellation of long-term contracts.
1
Unit averaged 61.4 working drilling rigs for 2010, up 58% from 38.9 during 2009.
Average per day operating margin for 2010 was $6,202 (before elimination of intercompany drilling rig profit of $9.2 million) as compared to $6,894 (before elimination of intercompany drilling rig profit and bad debt expense of $1.5 million) for 2009, a decrease of 10% (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below). Included in the average operating margin amount for 2010 and 2009 was a per day amount of $16 and $428, respectively, for early termination fees resulting from the cancellation of long-term contracts. Excluding early termination fees, average operating margins for 2010 were $6,186 per day, a decrease of $280 per day or 4% as compared to $6,466 per day for 2009.
The following table illustrates Unit’s drilling rig count at the end of each period and average utilization rate during the period:
| 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 |
2nd Qtr 09
|
1st Qtr 09
|
4th Qtr 08
|
|
|
Rigs
|
121 | 123 | 123 | 125 | 130 | 130 |
131
|
131
|
132
|
|
Utilization
|
59% | 54% | 47% | 40% | 28% | 26% |
24%
|
40%
|
74%
|
Larry Pinkston, Unit's Chief Executive Officer and President, said: “We are pleased with the results that our contract drilling segment has been able to obtain. The fourth quarter of 2010 was the sixth consecutive quarter in which we increased the average number of our working drilling rigs over the previous quarter. As the industry has continued to transition to drilling horizontal or directional wells, we have been able to respond to that demand by refurbishing rigs or adding new drilling rigs. Approximately 73% of our drilling rigs working today are drilling for oil or natural gas liquids and approximately 88% are drilling horizontal or directional wells. During 2010, we refurbished and upgraded 30 drilling rigs and during 2011 we have plans to add five new drilling rigs to our fleet. All five new drilling rigs are under long-term contracts and are 1,500 horsepower, diesel-electric drilling rigs. On completion of these new drilling rigs, our rig fleet will total 126 drilling rigs. Currently, 72 of our drilling rigs are under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 38 of the 72 contracted drilling rigs. Of these contracts nine are up for renewal during the first quarter of 2011, 11 during the second quarter of 2011, six during the third quarter of 2011, nine during the fourth quarter of 2011, and three in 2012 and beyond. These contracts do not include the five term contracts for the new drilling rigs.”
OIL AND NATURAL GAS SEGMENT INFORMATION
|
·
|
Completed 167 gross wells during 2010 with a success rate of 90%.
|
|
·
|
Continued strategy of focusing development activities on oil and natural gas liquids (NGLs) by increasing 2010 net proved oil and NGLs reserves 27% over 2009.
|
|
·
|
Hedged 80,000 MMBtu per day of natural gas and 4,000 Bbls per day of oil for 2011.
|
|
·
|
Currently anticipate 2011 production of 66.0 to 68.0 Bcfe.
|
Fourth quarter 2010 oil production was 519,000 barrels, in comparison to 295,000 barrels for the same period of 2009, up 76%. Natural gas liquids (NGLs) production during the fourth quarter of 2010 was 406,000 barrels, an increase of 17% when compared to 346,000 barrels for the same period of 2009. Fourth quarter 2010 natural gas production increased 1% to 10.6 billion cubic feet (Bcf) compared to 10.5 Bcf for the comparable quarter of 2009. Fourth quarter 2010 equivalent production totaled 16.2 Bcfe, up 13% from the fourth quarter of 2009 and up 8% from the third quarter of 2010. Total production for 2010 was 59.2 Bcfe, down 3% over the 60.7 Bcfe produced during 2009.
Unit’s average natural gas price, including the effects of hedges, for the fourth quarter of 2010 decreased 7% to $5.39 per thousand cubic feet (Mcf) as compared to $5.77 per Mcf for the fourth quarter of 2009. Unit’s average oil price, including the effects of hedges, for the fourth quarter of 2010 increased 21% to $74.28 per barrel compared to $61.57 per barrel for the fourth quarter of 2009. Unit’s average NGLs price, including the effects of hedges, for the fourth quarter of 2010 was $40.16 per barrel compared to $26.02 per barrel for the fourth quarter of 2009, up 54%.
For 2010, Unit’s average natural gas price, including the effects of hedges, increased 1% to $5.62 per Mcf as compared to $5.59 per Mcf for 2009. Unit’s average oil price, including the effects of hedges, for 2010 was $69.52 per barrel compared to $56.33 per barrel during 2009, a 23% increase. Unit’s average NGLs price, including the effects of hedges, for 2010 was $37.04 per barrel compared to $22.81 per barrel during 2009, a 62% increase.
For 2011, Unit has hedged 80,000 MMBtu per day of its natural gas production, 4,000 Bbls per day of its oil production and 504 Bbls per day of its NGLs production. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $4.85. The average basis differential for the swaps is ($0.19). The oil production is hedged under swap contracts at an average price of $84.28 per barrel. The NGLs production is hedged under swap contracts at an average price of $40.76 per barrel.
2
For 2012, Unit has hedged approximately 30,000 MMBtu per day of its natural gas production and 2,500 Bbls per day of its oil production. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.48. The average basis differential for the swaps is ($0.28). The oil production is hedged under swap contracts at an average price of $88.49 per barrel.
The following table illustrates Unit’s production and certain other results for the periods indicated:
| 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 |
2nd Qtr 09
|
1st Qtr 09
|
4th Qtr 08
|
|
|
Production, Bcfe
|
16.2 | 14.9 | 14.0 | 14.1 | 14.3 | 14.7 |
15.4
|
16.3
|
16.8
|
| Production, MMcfe/day | 176.0 | 162.2 | 153.3 | 156.8 | 155.8 | 159.4 | 169.6 | 180.9 | 182.6 |
|
Realized Price, Mcfe (1)
|
$6.93 | $6.36 | $6.37 | $6.82 | $6.12 | $5.92 |
$5.75
|
$5.48
|
$6.21
|
|
Wells Drilled
|
62 | 39 | 39 | 27 | 37 | 21 |
16
|
21
|
67
|
|
Success Rate
|
95% | 85% | 92% | 96% | 92% | 90% |
100%
|
90%
|
90%
|
(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
Pinkston said: “2010 was a transition year for us with regards to our drilling program as we continued to implement our strategy to focus on oil or NGLs rich prospects. Getting wells online were delayed by difficulties in securing fracing services and connections to gathering systems. During the latter part of the year, we were able to obtain these services and reduce the unusually large backlog of our well completions, especially in the Granite Wash and Marmaton plays.”
“We recently announced our total proved oil and natural gas reserves at December 31, 2010 were 622.2 Bcfe of natural gas, an 8% increase over our 2009 total proved reserves. The reserve growth consisted of a 50% and 10% increase in oil and NGLs, respectively, while natural gas reserves were essentially unchanged. Our production replacement for 2010 was 176%, with 158% through the drill bit. The capital expenditure budget for 2011 is $415 million, an 11% increase over 2010. Our preliminary annual production guidance for 2011 is approximately 66.0 to 68.0 Bcfe, an increase of 11% to 15% over 2010.”
MID-STREAM SEGMENT INFORMATION
|
·
|
Increased 2010 processing volumes per day and liquids sold volumes per day by 8% and 11%, respectively, over 2009.
|
|
·
|
Completed the Lone Tree Gas Processing Plant in Hemphill County, Texas.
|
|
·
|
Constructing a 16-mile pipeline and related compressor station in Preston County, West Virginia.
|
Fourth quarter of 2010 per day processing volumes were 85,195 MMBtu while liquids sold volumes were 291,186 gallons per day, an increase of 10% each, over the fourth quarter of 2009. Fourth quarter 2010 per day gathering volumes were 188,252 MMBtu, up 6% over the fourth quarter of 2009. Operating profit (as defined in the Selected Financial and Operational Highlights) for the fourth quarter was $9.9 million, an increase of 10% from the fourth quarter of 2009, primarily due to increased processing margins resulting from increased liquids prices and increased volumes.
For 2010, processing volumes were 82,175 MMBtu per day and liquids sold volumes were 271,360 gallons per day, an increase of 8% and 11%, respectively, over 2009. Gathering volumes for 2010 were 183,867 MMBtu per day, essentially unchanged from 2009.
The following table illustrates certain results from this segment’s operations for the periods indicated:
| 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 |
2nd Qtr 09
|
1st Qtr 09
|
4th Qtr 08
|
|
|
Gas gathered
MMBtu/day
|
188,252 | 183,161 | 183,858 | 180,117 | 177,145 | 179,047 |
187,666
|
192,320
|
187,585
|
|
Gas processed
MMBtu/day
|
85,195 | 84,175 | 82,699 | 76,513 | 77,501 | 77,923 |
75,481
|
72,650
|
72,491
|
|
Liquids sold
Gallons/day
|
291,186 | 260,519 | 279,736 | 253,707 | 263,668 | 251,830 |
239,121
|
218,762
|
197,428
|
3
Pinkston said: “Gas processed volumes, liquids sold volumes as well as gas gathered volumes all continued to increase and remained strong in the fourth quarter. We recently announced the completion of the Lone Tree Gas Processing Plant, a 50 MMcf per day turbo-expander natural gas processing plant at our Hemphill Processing Complex in Hemphill County, Texas. The completion of this new natural gas processing plant increases our Hemphill facility’s processing capacity to approximately 100 MMcf per day, with run rates expected at 70 to 80 MMcf per day by the middle of the second quarter.”
“In connection with our Appalachian operations, we are currently constructing a 16-mile, 16" pipeline and related compressor station in Preston County, West Virginia, which will have a capacity of approximately 220 MMcf per day. This pipeline project is on schedule to be completed by mid-2011.”
FINANCIAL INFORMATION
Unit ended the year with working capital of $41.1 million, long-term debt of $163.0 million, and a debt to capitalization ratio of 9%. Under its credit facility, the amount available to be borrowed is the lesser of the amount the company elects as the commitment amount (currently $325 million) or the value of the borrowing base as determined by the lenders (currently $500 million), but, in either event, not to exceed the maximum credit facility amount of $400 million.
MANAGEMENT COMMENT
Larry Pinkston said: “We are pleased with our 2010 fourth quarter and the positive momentum each of our business segments carries into 2011. We will continue to focus our exploration operations on oil and natural gas liquids rich plays like the Granite Wash and Marmaton and will continue to refurbish and upgrade certain drilling rigs while adding new rigs to our fleet as we respond to the demand for horizontal drilling by exploration and production companies. Our mid-stream segment will continue to grow with new pipeline projects, the expansion of existing facilities and exploring for additional opportunities in various basins throughout the country.”
WEBCAST
Unit will webcast its fourth quarter and year end earnings conference call live over the Internet on February 22, 2011 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to www.unitcorp.com 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 twelve months.
_____________________________________________________
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, availability and timing of obtaining third party services used in the drilling or completion of its oil and gas wells, 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.
4
Unit Corporation
Selected Financial and Operations Highlights
(In thousands except per share and operations data)
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||
|
December 31,
|
December 31,
|
|||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||
|
Statement of Operations:
|
||||||||||||
|
Revenues:
|
||||||||||||
|
Contract drilling
|
$
|
98,465
|
$
|
47,932
|
$
|
316,384
|
$
|
236,315
|
||||
|
Oil and natural gas
|
114,056
|
90,480
|
400,807
|
357,879
|
||||||||
|
Gas gathering and processing
|
39,608
|
37,024
|
154,516
|
108,628
|
||||||||
|
Other, net
|
447
|
1,896
|
10,138
|
7,076
|
||||||||
|
Total revenues
|
252,576
|
177,332
|
881,845
|
709,898
|
||||||||
|
Expenses:
|
||||||||||||
|
Contract drilling:
|
||||||||||||
|
Operating costs
|
53,966
|
30,515
|
186,813
|
140,080
|
||||||||
|
Depreciation
|
21,270
|
11,523
|
69,970
|
45,326
|
||||||||
|
Oil and natural gas:
|
||||||||||||
|
Operating costs
|
29,422
|
24,888
|
105,365
|
87,734
|
||||||||
|
Depreciation, depletion
|
||||||||||||
|
and amortization
|
37,047
|
24,881
|
118,793
|
114,681
|
||||||||
|
Impairment of oil and natural
gas properties
|
---
|
---
|
---
|
281,241
|
||||||||
|
Gas gathering and processing:
|
||||||||||||
|
Operating costs
|
29,739
|
28,020
|
122,146
|
87,908
|
||||||||
|
Depreciation
|
||||||||||||
|
and amortization
|
3,639
|
3,938
|
15,385
|
16,104
|
||||||||
|
General and administrative
|
6,780
|
6,923
|
26,152
|
24,011
|
||||||||
|
Interest, net
|
---
|
---
|
---
|
539
|
||||||||
|
Total expenses
|
181,863
|
130,688
|
644,624
|
797,624
|
||||||||
|
Income (Loss) Before Income Taxes
|
70,713
|
46,644
|
237,221
|
(87,726
|
)
|
|||||||
|
Income Tax Expense (Benefit):
|
||||||||||||
|
Current
|
(7,447
|
)
|
(10,041
|
)
|
(9,935
|
)
|
(223
|
)
|
||||
|
Deferred
|
34,495
|
28,172
|
100,672
|
(32,003
|
)
|
|||||||
|
Total income taxes
|
27,048
|
18,131
|
90,737
|
(32,226
|
)
|
|||||||
|
Net Income (Loss)
|
$
|
43,665
|
$
|
28,513
|
$
|
146,484
|
$
|
(55,500
|
)
|
|||
|
Net Income (Loss) per
Common Share:
|
||||||||||||
|
Basic
|
$
|
0.92
|
$
|
0.61
|
$
|
3.10
|
$
|
(1.18
|
)
|
|||
|
Diluted
|
$
|
0.92
|
$
|
0.60
|
$
|
3.09
|
$
|
(1.18
|
)
|
|||
|
Weighted Average Common
|
||||||||||||
|
Shares Outstanding:
|
||||||||||||
|
Basic
|
47,457
|
47,020
|
47,278
|
46,990
|
||||||||
|
Diluted
|
47,678
|
47,503
|
47,454
|
46,990
|
||||||||
5
|
December 31,
|
December 31,
|
||||||||
|
2010
|
2009
|
||||||||
|
Balance Sheet Data:
|
|||||||||
|
Current assets
|
$
|
188,180
|
$
|
128,095
|
|||||
|
Total assets
|
$
|
2,669,240
|
$
|
2,228,399
|
|||||
|
Current liabilities
|
$
|
147,128
|
$
|
105,147
|
|||||
|
Long-term debt
|
$
|
163,000
|
$
|
30,000
|
|||||
|
Other long-term liabilities
|
$
|
92,389
|
$
|
81,126
|
|||||
|
Deferred income taxes
|
$
|
556,106
|
$
|
446,316
|
|||||
|
Shareholders’ equity
|
$
|
1,710,617
|
$
|
1,565,810
|
|||||
|
Twelve Months Ended December 31,
|
|||||||||
|
2010
|
2009
|
||||||||
|
Statement of Cash Flows Data:
|
|||||||||
|
Cash Flow From Operations before Changes
|
|||||||||
|
in Operating Assets and Liabilities (1)
|
$
|
454,492
|
$
|
380,762
|
|||||
|
Net Change in Operating Assets and Liabilities
|
(64,420
|
)
|
109,713
|
||||||
|
Net Cash Provided by Operating Activities
|
$
|
390,072
|
$
|
490,475
|
|||||
|
Net Cash Used in Investing Activities
|
$
|
(536,261
|
)
|
$
|
(271,927
|
)
|
|||
|
Net Cash Provided by (Used in)
Financing Activities
|
$
|
146,408
|
$
|
(217,992
|
)
|
||||
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||
|
December 31,
|
December 31,
|
|||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||
|
Contract Drilling Operations Data:
|
||||||||||||
|
Rigs Utilized
|
70.9
|
36.7
|
61.4
|
38.9
|
||||||||
|
Operating Margins (2)
|
45%
|
36%
|
41%
|
41%
|
||||||||
|
Operating Profit Before Depreciation (2) ($MM)
|
$
|
44.4
|
$
|
17.4
|
$
|
129.6
|
$
|
96.2
|
||||
|
Oil and Natural Gas Operations Data:
|
||||||||||||
|
Production:
|
||||||||||||
|
Oil – MBbls
|
519
|
295
|
1,521
|
1,286
|
||||||||
|
Natural Gas Liquids - MBbls
|
406
|
346
|
1,549
|
1,488
|
||||||||
|
Natural Gas - MMcf
|
10,635
|
10,489
|
40,756
|
44,063
|
||||||||
|
Average Prices:
|
||||||||||||
|
Oil price per barrel received
Oil price per barrel received, excluding hedges
|
$
$
|
74.28
81.56
|
$
$
|
61.57
73.02
|
$
$
|
69.52
76.65
|
$
$
|
56.33
56.64
|
||||
|
NGLs price per barrel received
NGLs price per barrel received,
excluding hedges
|
$
$
|
40.16
40.59
|
$
$
|
26.02
36.10
|
$
$
|
37.04
36.96
|
$
$
|
22.81
25.66
|
||||
|
Natural Gas price per Mcf received
Natural Gas price per Mcf received,
excluding hedges
|
$
$
|
5.39
3.41
|
$
$
|
5.77
3.90
|
$
$
|
5.62
4.05
|
$
$
|
5.59
3.26
|
||||
|
Operating Profit Before DD&A and
|
||||||||||||
|
Impairment (2) ($MM)
|
$
|
84.6
|
$
|
65.6
|
$
|
295.4
|
$
|
270.1
|
||||
|
Mid-Stream Operations Data:
|
||||||||||||
|
Gas Gathering - MMBtu/day
|
188,252
|
177,145
|
183,867
|
183,989
|
||||||||
|
Gas Processing - MMBtu/day
|
85,195
|
77,501
|
82,175
|
75,908
|
||||||||
|
Liquids Sold – Gallons/day
|
291,186
|
263,668
|
271,360
|
243,492
|
||||||||
|
Operating Profit Before Depreciation
|
||||||||||||
|
and Amortization (2) ($MM)
|
$
|
9.9
|
$
|
9.0
|
$
|
32.4
|
$
|
20.7
|
||||
_____________
(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 and impairment, general and administrative and interest expense. Operating margins are calculated by dividing operating profit by segment revenue.
6
Non-GAAP Financial Measures
We report our financial results in accordance with generally accepted account 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, 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 drilling rig profit.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2010 and 2009. Non-GAAP financial measures should not be considered by themselves or a substitute for our results reported in accordance with GAAP.
Unit Corporation
Reconciliation of Net Income and Earnings per Share
Excluding the Effect of Impairment of Oil and Natural Gas Properties
|
Three Months Ended
|
Twelve Months Ended
|
||||||||||||||
|
December 31,
|
December 31,
|
||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
||||||||||||
|
(In thousands except per share amounts)
|
|||||||||||||||
|
Net income excluding impairment of oil and
|
|||||||||||||||
|
natural gas properties:
|
|||||||||||||||
|
Net income (loss)
|
$
|
43,665
|
$
|
28,513
|
$
|
146,484
|
$
|
(55,500
|
)
|
||||||
|
Add:
|
|||||||||||||||
|
Impairment of oil and natural gas properties
|
|||||||||||||||
|
(net of income tax)
|
---
|
---
|
---
|
175,072
|
|||||||||||
|
Net income excluding impairment of oil and
|
|||||||||||||||
|
natural gas properties
|
$
|
43,665
|
$
|
28,513
|
$
|
146,484
|
$
|
119,572
|
|||||||
|
Diluted earnings per share excluding
|
|||||||||||||||
|
impairment of oil and natural gas properties:
|
|||||||||||||||
|
Diluted earnings per share
Add:
Diluted earnings per share from impairment
|
$
|
0.92
|
$
|
0.60
|
$
|
3.09
|
$
|
(1.18
|
)
|
||||||
|
of oil and natural gas properties
|
---
|
---
|
---
|
3.70
|
|||||||||||
|
Diluted earnings per share excluding
|
|||||||||||||||
|
impairment of oil and natural gas properties
|
$
|
0.92
|
$
|
0.60
|
$
|
3.09
|
$
|
2.52
|
|||||||
________________
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 analysts.
|
|
·
|
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.
|
7
Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
|
Twelve Months Ended
December 31,
|
||||||||||||
|
2010
|
2009
|
|||||||||||
|
(In thousands)
|
||||||||||||
|
Net cash provided by operating activities
|
$
|
390,072
|
$
|
490,475
|
||||||||
|
Net change in operating assets and liabilities
|
64,420
|
(109,713
|
)
|
|||||||||
|
Cash flow from operations before changes
|
||||||||||||
|
in operating assets and liabilities
|
$
|
454,492
|
$
|
380,762
|
||||||||
________________
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 Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit
|
Three Months Ended
|
Three Months Ended
|
Twelve Months Ended
|
||||||||||||||||
|
September 30,
|
December 31,
|
December 31,
|
||||||||||||||||
|
2010
|
2010
|
2009
|
2010
|
2009
|
||||||||||||||
|
(In thousands except day and daily data)
|
||||||||||||||||||
|
Contract drilling revenue
|
$
|
85,004
|
$
|
98,465
|
$
|
47,932
|
$
|
316,384
|
$
|
236,315
|
||||||||
|
Contract drilling operating cost
|
45,406
|
53,966
|
30,515
|
186,813
|
140,080
|
|||||||||||||
|
Operating profit from contract drilling
|
39,598
|
44,499
|
17,417
|
129,571
|
96,235
|
|||||||||||||
|
Add:
Elimination of intercompany rig profit
and bad debt expense
|
2,888
|
4,440
|
377
|
9,158
|
1,549
|
|||||||||||||
|
Operating profit from contract drilling
|
||||||||||||||||||
|
before elimination of intercompany
|
||||||||||||||||||
|
rig profit and bad debt expense
|
42,486
|
48,939
|
17,794
|
138,729
|
97,784
|
|||||||||||||
|
Contract drilling operating days
|
6,021
|
6,474
|
3,378
|
22,367
|
14,183
|
|||||||||||||
|
Average daily operating margin before
|
||||||||||||||||||
|
elimination of intercompany rig profit
and bad debt expense
|
$
|
7,056
|
$
|
7,559
|
$
|
5,268
|
$
|
6,202
|
$
|
6,894
|
||||||||
________________
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.
|
8