Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) announced today net income of $31.4 million, or $0.66 per diluted share, for the three months ended September 30, 2009, compared to net income of $92.3 million, or $1.96 per diluted share, for the three months ended September 30, 2008. Total revenues for the third quarter of 2009 were $167.4 million (30% contract drilling, 53% oil and natural gas, and 16% mid-stream), compared to total revenues for the third quarter of 2008 of $375.6 million (45% contract drilling, 41% oil and natural gas, and 14% mid-stream).
For the first nine months of 2009, Unit reported a net loss of $84.0 million, or $1.79 per diluted share, compared to net income of $263.5 million, or $5.61 per diluted share, for the nine months ended September 30, 2008. Included in the 2009 results is a $281.2 million ($175.1 million after tax, or $3.71 per diluted share) noncash ceiling test write down that occurred in the first quarter. The ceiling test write down was required to reduce the carrying value of the company’s oil and natural gas properties due to significantly lower commodity prices at the end of the first quarter 2009. Excluding the ceiling test write down, net income for the first nine months of 2009 would have been $91.1 million, or $1.92 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the first nine months of 2009 were $532.6 million (35% contract drilling, 50% oil and natural gas, and 13% mid-stream), compared to $1.1 billion (44% contract drilling, 42% oil and natural gas, and 14% mid-stream) for the first nine months of 2008.
CONTRACT DRILLING SEGMENT INFORMATION
Average drilling rig utilization for the third quarter of 2009 was 34.6 drilling rigs, or 26%, a decrease of 69% from the third quarter of 2008, and an increase of 9% from the second quarter of 2009. Contract drilling rig rates for the third quarter of 2009 averaged $15,360 per day, a decrease of 18%, or $3,284 per day, from the third quarter of 2008, and a decrease of 11%, or $1,975 per day, from the second quarter of 2009. Average operating margins for the third quarter of 2009 were $6,433 per day (before elimination of intercompany drilling rig profit of $0.1 million; see Non-GAAP Financial Measures below) as compared to $9,314 per day (before elimination of intercompany drilling rig profit of $7.6 million; see Non-GAAP Financial Measures below) for the same quarter in 2008, a decrease of 31%. Approximately $1,104 per day of the third quarter 2009 average operating margin was the result of early termination fees associated with the cancellation of long-term contracts.
For the first nine months of 2009, drilling rig utilization averaged 30% as compared to 81% for the same period during 2008. Unit averaged 39.6 drilling rigs working during the first nine months of 2009, a decrease of 62% from the 105.3 drilling rigs working during the first nine months of 2008. Average operating margins for the first nine months of 2009 were $7,403 per day (before elimination of intercompany drilling rig profit of $1.2 million; see Non-GAAP Financial Measures below) as compared to $8,821 per day (before elimination of intercompany drilling rig profit of $21.5 million for the same period in 2008; see Non-GAAP Financial Measures below), a decrease of 16%. Approximately $368 per day of the first nine months of 2009 average operating margin was the result of early termination fees associated with the cancellation of long-term contracts.
Currently, Unit has 130 drilling rigs of which 40 are under contract. The following table illustrates this segment’s drilling rig count at the end of each period and its average utilization rate during the period:
| | 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | 1st Qtr 08 | 4th Qtr 07 | 3rd Qtr 07 |
| Rigs | 130 | 131 | 131 | 132 | 131 | 131 | 129 | 129 | 128 |
| Utilization | 26% | 24% | 40% | 74% | 85% | 80% | 78% | 80% | 78% |
Larry Pinkston, Unit's Chief Executive Officer and President, said: “While low commodity prices and minimal capital spending by exploration and production companies continued to negatively impact dayrates during the third quarter, we did experience a slight increase in demand for our rigs in the spot market. Additionally, during the third quarter we sold one of our inactive 1,000 horsepower, mechanical drilling rigs, bringing our total fleet to 130 drilling rigs. We believe that as the supply of natural gas declines due to fewer wells being drilled, the demand for drilling rigs will grow as long as we see improvements in the domestic and global economy.”
OIL AND NATURAL GAS SEGMENT INFORMATION
| · | Completed 21 and 58 gross wells during the 2009 third quarter and first nine months, respectively. |
| · | Curtailed approximately 4.4 MMcf per day of production during the third quarter of 2009 due to low commodity prices and the shut-in of a third party plant. |
| · | Approximately 76% of anticipated natural gas production and 71% of anticipated crude oil production is hedged for the remainder of 2009. |
| · | Revised estimate of gross wells to be drilled from 120 to 100 wells during 2009. |
Third quarter 2009 production was 300,000 barrels of oil, in comparison to 316,000 barrels of oil in the third quarter of 2008, a 5% decrease. Natural gas liquids (NGLs) production during the third quarter of 2009 was 358,000 barrels in comparison to 306,000 barrels in the third quarter of 2008, a 17% increase. Third quarter 2009 natural gas production decreased 12% to 10.7 billion cubic feet (Bcf) from 12.1 Bcf during the comparable quarter of 2008. Third quarter 2009 equivalent production totaled 14.7 Bcfe, an 8% decrease over the third quarter 2008. Total production for the first nine months of 2009 was 46.4 Bcfe, a decrease of 0.4% over the 46.6 Bcfe produced during the first nine months of 2008.
Unit’s average natural gas price for the third quarter of 2009 decreased 31% to $5.67 per thousand cubic feet (Mcf) as compared to $8.20 per Mcf for the third quarter of 2008. Unit’s average oil price for the third quarter of 2009 was $59.55 per barrel compared to $101.82 per barrel for the third quarter of 2008, a 42% decrease, and Unit’s average NGLs price for the third quarter of 2009 was $22.99 per barrel compared to $61.78 per barrel for the third quarter of 2008, a 63% decrease. For the first nine months of 2009, Unit’s average natural gas price decreased 34% to $5.53 per Mcf as compared to $8.35 per Mcf during the first nine months of 2008. Unit’s average oil price for the first nine months of 2009 was $54.77 per barrel compared to $99.33 per barrel during the first nine months of 2008, a 45% decrease. Unit’s average NGLs price for the first nine months of 2009 was $21.80 per barrel compared to $56.87 per barrel during the first nine months of 2008, a 62% decrease.
For 2009, approximately 76% of this segment's anticipated average daily natural gas production is hedged through NYMEX plus basis at several delivery points and approximately 71% of its anticipated oil production is hedged. Of the natural gas hedges, 89% are under swap contracts at a comparable NYMEX average price of $7.20 and 11% are under a collar contract with a comparable NYMEX floor of $8.22 and a ceiling of $10.80. The average basis differentials for these swaps are ($0.85). Of the oil hedges, 80% are under swap contracts at an average price of $51.87 and 20% under a collar contract with a floor of $100.00 and a ceiling of $156.25. For 2010, approximately 68% of the company’s anticipated average daily natural gas production is hedged and 71% of its anticipated daily oil production is hedged. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $6.95. The average basis differentials for the swaps are ($0.66). Of the oil hedges, 60% are under swap contracts at an average price of $61.36 and 40% are under a collar contract with a floor of $67.50 and a ceiling of $81.53. Additionally, Unit has hedged approximately 73% of its anticipated average daily NGLs production for the balance of 2009.
The following table illustrates this segment’s production and certain results for the periods indicated:
| | 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | 1st Qtr 08 | 4th Qtr 07 | 3rd Qtr 07 |
| Production, Bcfe | 14.7 | 15.4 | 16.3 | 16.8 | 15.9 | 16.0 | 14.7 | 14.7 | 14.0 |
| Realized Price, Mcfe | $5.92 | $5.75 | $5.48 | $6.21 | $9.49 | $10.19 | $8.72 | $7.66 | $6.69 |
| Wells Drilled (gross) | 21 | 16 | 21 | 67 | 82 | 72 | 57 | 81 | 51 |
| Success Rate | 90% | 100% | 90% | 90% | 89% | 90% | 86% | 90% | 88% |
(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
During the third quarter of 2009, Unit participated in the drilling of 21 wells, of which 19 were completed as producing wells for a success rate of 90% in comparison to the completion of 82 wells with an 89% success rate during the third quarter of 2008.
Pinkston said: “During the third quarter of 2009, we increased our level of drilling activity to take advantage of the reduction in well costs that have occurred throughout the year. Our drilling efforts continue to be focused in prospects that have a combination of natural gas and oil or where the natural gas has a high BTU content, yielding NGLs which are better correlated to crude pricing. Production for the third quarter of 2009 was reduced by approximately 4.4 MMcf per day that was curtailed due to weak commodity prices or shut-in due to third party plant issues. We plan to drill approximately 100 wells during 2009, a reduction from our previous estimate of 120 wells, and estimate that our production for the year will be approximately 62 Bcfe.”
MID-STREAM SEGMENT INFORMATION
| · | Increased third quarter 2009 liquids sold per day volumes 5% over second quarter of 2009 and 26% over third quarter of 2008. |
| · | Increased third quarter 2009 processed volumes per day 3% over second quarter 2009 and 9% over third quarter of 2008. |
| · | 29 new wells connected to existing systems during the first nine months of 2009. |
Third quarter of 2009 processing volumes of 77,923 MMBtu per day and liquids sold volumes of 251,830 gallons per day increased 9% and 26%, respectively, over third quarter of 2008. Third quarter 2009 gathering volumes were 179,047 MMBtu per day, a 9% decrease over third quarter of 2008. Operating profit (as defined in the Selected Financial and Operational Highlights) for the third quarter was $6.2 million, an increase of $2.2 million from the second quarter of 2009, due primarily to increased liquids prices and increases in liquids sold and processed volumes, which resulted in increased processing margins.
For the first nine months of 2009, processing volumes of 75,371 MMBtu per day and liquids sold volumes of 236,692 gallons per day increased 14% and 21%, respectively, from the first nine months of 2008. Gathering volumes for the first nine months of 2009 were 186,296 MMBtu per day, a 7% decrease from the first nine months of 2008.
The following table illustrates certain results from this segment’s operations for the periods indicated:
| 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | 1st Qtr 08 | 4th Qtr 07 | 3rd Qtr 07 |
Gas gathered MMBtu/day | 179,047 | 187,666 | 192,320 | 187,585 | 195,914 | 205,397 | 200,697 | 212,786 | 221,508 |
Gas processed MMBtu/day | 77,923 | 75,481 | 72,650 | 72,491 | 71,260 | 67,545 | 59,797 | 59,009 | 55,721 |
Liquids sold Gallons/day | 251,830 | 239,121 | 218,762 | 197,428 | 199,805 | 202,130 | 183,924 | 169,897 | 137,098 |
Unit’s mid-stream segment operates three natural gas treatment plants, owns eight processing plants, 34 active gathering systems and 835 miles of pipeline.
Pinkston said: “Both our liquids sold volumes per day as well as our gas processed volumes per day were at record high levels for the company. Despite the reduced drilling activity by exploration and production companies, we are pleased with the volume growth that our mid-stream segment has been able to achieve to date primarily through our efforts to improve liquid recovery rates at our plants.”
FINANCIAL INFORMATION
Unit ended the third quarter of 2009 with long-term debt of $30.0 million and a debt to capitalization ratio of 2%. Under the company’s credit facility, the amount available to the company is the lesser of the amount elected by the company as the commitment amount (currently $325 million) or the value of the borrowing base as determined by the lenders under the credit facility, but not to exceed the maximum credit facility amount of $400 million. As of October 1, 2009, Unit’s borrowing base was reaffirmed by its lenders at $475 million. The company is currently in compliance with all of the covenants contained in its credit facility.
MANAGEMENT COMMENT
Larry Pinkston said: “We are pleased with the results of our 2009 third quarter as the challenges to the economy and our industry persist. Unit had borrowings outstanding of $30.0 million at the end of the third quarter, which is $81.0 million less than the $111 million outstanding at the end of the second quarter. The reduction in borrowings was primarily funded from lower capital
spending relative to cash flow, supported by a strong commodity hedge position, along with proceeds from the sale of certain Appalachia acreage and related collection of third party costs. Sustained improvement in all three of our business segments will require increases in underlying commodity prices. We believe initial signs of increased demand for drilling activity by exploration and production companies have materialized, and we are well positioned with the personnel, prospects, rig fleet and financial capacity to take advantage of low-cost growth opportunities for our shareholders.”
WEBCAST
Unit will webcast its third quarter earnings conference call live over the Internet on November 3, 2009 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.
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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 the ability to meet its future reserve replacement goals, anticipated gas gathering and processing rates and throughput volumes, the prospective capabilities of the reserves associated with the Company’s inventory of future drilling sites, anticipated oil and natural gas prices, the number of wells to be drilled by the Company’s oil and natural gas segment, development, operational, implementation and opportunity risks, possibility of future growth opportunities, and other factors described from time to time in the Company’s publicly available SEC reports. The Company assumes no obligation to update publicly such forward-looking statements, whether as a result of new information, future events or otherwise.
Unit Corporation
Selected Financial and Operations Highlights
(In thousands except per share and operations data)
| | Three Months Ended | | Nine Months Ended | |
| | September 30, | | September 30, | |
| | 2009 | | 2008 | | 2009 | | 2008 | |
| Statement of Income: | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | |
| Contract drilling | $ | 49,801 | | $ | 169,044 | | $ | 188,383 | | $ | 467,519 | |
| Oil and natural gas | | 88,894 | | | 152,343 | | | 267,399 | | | 446,644 | |
| Gas gathering and processing | | 26,228 | | | 54,079 | | | 71,604 | | | 153,102 | |
| Other | | 2,507 | | | 97 | | | 5,180 | | | (193 | ) |
| Total revenues | | 167,430 | | | 375,563 | | | 532,566 | | | 1,067,072 | |
| | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | |
| Contract drilling: | | | | | | | | | | | | |
| Operating costs | | 29,456 | | | 81,802 | | | 109,565 | | | 234,541 | |
| Depreciation | | 10,923 | | | 18,968 | | | 33,803 | | | 51,320 | |
| Oil and natural gas: | | | | | | | | | | | | |
| Operating costs | | 20,781 | | | 32,095 | | | 62,846 | | | 90,353 | |
| Depreciation, depletion | | | | | | | | | | | | |
| and amortization | | 25,645 | | | 40,053 | | | 89,800 | | | 114,756 | |
Impairment of oil and natural gas properties | | --- | | | --- | | | 281,241 | | | --- | |
| Gas gathering and processing: | | | | | | | | | | | | |
| Operating costs | | 20,012 | | | 45,381 | | | 59,888 | | | 125,617 | |
| Depreciation | | | | | | | | | | | | |
| and amortization | | 3,995 | | | 3,788 | | | 12,166 | | | 10,932 | |
| General and administrative | | 5,506 | | | 6,928 | | | 17,088 | | | 20,179 | |
| Interest, net | | 1 | | | 69 | | | 539 | | | 1,162 | |
| Total expenses | | 116,319 | | | 229,084 | | | 666,936 | | | 648,860 | |
| Income (Loss) Before Income Taxes | | 51,111 | | | 146,479 | | | (134,370 | ) | | 418,212 | |
| | | | | | | | | | | | | |
| Income Tax Expense (Benefit): | | | | | | | | | | | | |
| Current | | 8,571 | | | 16,026 | | | 9,818 | | | 41,161 | |
| Deferred | | 11,091 | | | 38,172 | | | (60,175 | ) | | 113,578 | |
| Total income taxes | | 19,662 | | | 54,198 | | | (50,357 | ) | | 154,739 | |
| | | | | | | | | | | | | |
| Net Income (Loss) | $ | 31,449 | | $ | 92,281 | | $ | (84,013 | ) | $ | 263,473 | |
| | | | | | | | | | | | | |
Net Income (Loss) per Common Share: | | | | | | | | | | | | |
| Basic | $ | 0.67 | | $ | 1.98 | | $ | (1.79 | ) | $ | 5.66 | |
| Diluted | $ | 0.66 | | $ | 1.96 | | $ | (1.79 | ) | $ | 5.61 | |
| Weighted Average Common | | | | | | | | | | | | |
| Shares Outstanding: | | | | | | | | | | | | |
| Basic | | 47,011 | | | 46,634 | | | 46,980 | | | 46,568 | |
| Diluted | | 47,419 | | | 47,043 | | | 46,980 | | | 46,934 | |
| | | September 30, | | | | December 31, | |
| | | 2009 | | | | 2008 | |
Balance Sheet Data: | | | | | | | | | |
| Current assets | | $ | 111,858 | | | | $ | 286,585 | |
| Total assets | | $ | 2,163,268 | | | | $ | 2,581,866 | |
| Current liabilities | | $ | 95,434 | | | | $ | 196,399 | |
| Long-term debt | | $ | 30,000 | | | | $ | 199,500 | |
| Other long-term liabilities | | $ | 81,110 | | | | $ | 75,807 | |
| Deferred income taxes | | $ | 415,707 | | | | $ | 477,061 | |
| Shareholders’ equity | | $ | 1,541,017 | | | | $ | 1,633,099 | |
| | | Nine Months Ended September 30, | |
| | | 2009 | | | | 2008 | |
| Statement of Cash Flows Data: | | | | | | | | | |
| Cash Flow From Operations before Changes | | | | | | | | | |
| in Operating Assets and Liabilities (1) | | $ | 282,260 | | | | $ | 567,812 | |
| Net Change in Operating Assets and Liabilities | | | 140,310 | | | | | (42,745 | ) |
| Net Cash Provided by Operating Activities | | $ | 422,570 | | | | $ | 525,067 | |
| Net Cash Used in Investing Activities | | $ | (204,637 | ) | | | $ | (578,318 | ) |
Net Cash Provided by (Used in) Financing Activities | | $ | (217,371 | ) | | | $ | 53,182 | |
| | Three Months Ended | | Nine Months Ended | |
| | September 30, | | September 30, | |
| | 2009 | | 2008 | | 2009 | | 2008 | |
| Contract Drilling Operations Data: | | | | | | | | | | | | |
| Rigs Utilized | | 34.6 | | | 110.7 | | | 39.6 | | | 105.3 | |
| Operating Margins (2) | | 41% | | | 52% | | | 42% | | | 50% | |
| Operating Profit Before Depreciation (2) ($MM) | $ | 20.3 | | $ | 87.2 | | $ | 78.8 | | $ | 233.0 | |
| | | | | | | | | | | | | |
| Oil and Natural Gas Operations Data: | | | | | | | | | | | | |
| Production: | | | | | | | | | | | | |
| Oil – MBbls | | 300 | | | 316 | | | 991 | | | 942 | |
| Natural Gas Liquids - MBbls | | 358 | | | 306 | | | 1,142 | | | 961 | |
| Natural Gas - MMcf | | 10,713 | | | 12,134 | | | 33,575 | | | 35,143 | |
| Average Prices: | | | | | | | | | | | | |
Oil price per barrel received Oil price per barrel received, excluding hedges | $ $ | 59.55 64.75 | | $ $ | 101.82 117.56 | | $ $ | 54.77 51.76 | | $ $ | 99.33 112.15 | |
NGLs price per barrel received NGLs price per barrel received, excluding hedges | $ $ | 22.99 25.23 | | $ $ | 61.78 61.78 | | $ $ | 21.80 22.51 | | $ $ | 56.87 56.78 | |
Natural Gas price per Mcf received Natural Gas price per Mcf received, excluding hedges | $ $ | 5.67 2.96 | | $ $ | 8.20 8.34 | | $ $ | 5.53 3.06 | | $ $ | 8.35 8.58 | |
| Operating Profit Before DD&A and | | | | | | | | | | | | |
| impairment (2) ($MM) | $ | 68.1 | | $ | 120.2 | | $ | 204.6 | | $ | 356.3 | |
| | | | | | | | | | | | | |
| Gas Gathering and Processing Operations Data: | | | | | | | | | | | | |
| Gas Gathering - MMBtu/day | | 179,047 | | | 195,914 | | | 186,296 | | | 200,652 | |
| Gas Processing - MMBtu/day | | 77,923 | | | 71,260 | | | 75,371 | | | 66,219 | |
| Liquids Sold – Gallons/day | | 251,830 | | | 199,805 | | | 236,692 | | | 195,303 | |
| Operating Profit Before Depreciation | | | | | | | | | | | | |
| and Amortization (2) ($MM) | $ | 6.2 | | $ | 8.7 | | $ | 11.7 | | $ | 27.5 | |
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(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.
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 working capital 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 nine months ended September 30, 2009 and 2008. 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 | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | (In thousands) | |
| Net income excluding impairment of oil and | | | | | | | | | | | | | |
| natural gas properties: | | | | | | | | | | | | | |
| Net income (loss) | | $ | 31,449 | | $ | 92,281 | | $ | (84,013) | | $ | 263,473 | |
| Add: | | | | | | | | | | | | | |
| Impairment of oil and natural gas properties | | | | | | | | | | | | | |
| (net of income tax) | | | --- | | | --- | | | 175,072 | | | --- | |
| Net income excluding impairment of oil and | | | | | | | | | | | | | |
| natural gas properties | | $ | 31,449 | | $ | 92,281 | | $ | 91,059 | | $ | 263,473 | |
| | | | | | | | | | | | | | |
| Diluted earnings per share excluding | | | | | | | | | | | | | |
| impairment of oil and natural gas properties: | | | | | | | | | | | | | |
Diluted earnings per share Add: Diluted earnings per share from impairment | | $ | 0.66 | | $ | 1.96 | | $ | (1.79) | | $ | 5.61 | |
| of oil and natural gas properties | | | --- | | | --- | | | 3.71 | | | --- | |
| Diluted earnings per share excluding | | | | | | | | | | | | | |
| impairment of oil and natural gas properties | | $ | 0.66 | | $ | 1.96 | | $ | 1.92 | | $ | 5.61 | |
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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. |
Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
| | | Nine Months Ended September 30, | | | | |
| | | | 2009 | | | 2008 | | | | |
| | | (In thousands) | | | | | |
| Net cash provided by operating activities | | $ | 422,570 | | $ | 525,067 | | | | |
| Subtract: | | | | | | | | | | |
| Net change in operating assets and liabilities | | | 140,310 | | | (42,745) | | | | |
| Cash flow from operations before changes | | | | | | | | | | |
| in operating assets and liabilities | | $ | 282,260 | | $ | 567,812 | | | | |
________________
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 Rig Profit
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | | (In thousands) |
| Contract drilling revenue | | $ | 49,801 | | $ | 169,044 | | $ | 188,383 | | $ | 467,519 | |
| Contract drilling operating cost | | | 29,456 | | | 81,802 | | | 109,565 | | | 234,541 | |
| Operating profit from contract drilling | | | 20,345 | | | 87,242 | | | 78,818 | | | 232,978 | |
Add: Elimination of intercompany rig profit | | | 107 | | | 7,596 | | | 1,172 | | | 21,460 | |
| Operating profit from contract drilling | | | | | | | | | | | | | |
| before elimination of intercompany | | | | | | | | | | | | | |
| rig profit | | | 20,452 | | | 94,838 | | | 79,990 | | | 254,438 | |
| Contract drilling operating days | | | 3,179 | | | 10,182 | | | 10,805 | | | 28,846 | |
| Average daily operating margin before | | | | | | | | | | | | | |
| elimination of rig profit | | $ | 6,433 | | $ | 9,314 | | $ | 7,403 | | $ | 8,821 | |
________________
We have included the average daily operating margin before elimination of rig profit because:
| · | Our management uses the measurement to evaluate the cash flow performance or 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. |
