Attached files
| file | filename |
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| 8-K - FORM 8-K - UNIT CORP | form8k02212012.htm |
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News
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UNIT CORPORATION
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7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136
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Telephone 918 493-7700, Fax 918 493-7714
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Contact:
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David T. Merrill
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Chief Financial Officer
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and Treasurer
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(918) 493-7700
www.unitcorp.com
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For Immediate Release…
February 21, 2012
UNIT CORPORATION REPORTS 2011 FOURTH QUARTER AND YEAR END RESULTS
Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) reported net income of $51.7 million, or $1.08 per diluted share, for the three months ended December 31, 2011. For the same period in 2010, net income was $43.7 million, or $0.92 per diluted share. Total revenues for the fourth quarter of 2011 were $345.6 million (41% contract drilling, 41% oil and natural gas, and 18% mid-stream), compared to $252.6 million (39% contract drilling, 45% oil and natural gas, and 16% mid-stream) for the fourth quarter of 2010.
For all of 2011, Unit reported net income of $195.9 million, or $4.08 per diluted share. For the same period in 2010, net income was $146.5 million, or $3.09 per diluted share. Total revenues for all of 2011 were $1,208.4 million (40% contract drilling, 43% oil and natural gas, and 17% mid-stream), compared to $881.8 million (36% contract drilling, 45% oil and natural gas, and 18% mid-stream) for the same period in 2010.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the fourth quarter of 2011 was 82.1, an increase of 16% from the fourth quarter of 2010, and an increase of 4% from the third quarter of 2011. Per day drilling rig rates for the fourth quarter of 2011 averaged $19,330, an increase of 17%, or $2,760, from the fourth quarter of 2010, and essentially unchanged from the third quarter of 2011. Average per day operating margin for the fourth quarter of 2011 was $9,037 (before elimination of intercompany drilling rig profit and bad debt expense of $4.9 million). This compares to $7,559 (before elimination of intercompany drilling rig profit of $4.4 million) for the fourth quarter of 2010, an increase of 20% or $1,478. As compared to the third quarter of 2011 ($8,413 before elimination of intercompany drilling rig profit of $4.8 million) fourth quarter 2011 operating margin increased 7% (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below).
For all of 2011, Unit averaged 76.1 drilling rigs working, an increase of 24% from 61.4 drilling rigs working during 2010. Average per day operating margin for all of 2011 was $8,496 (before elimination of intercompany drilling rig profit and bad debt expense of $19.9 million) as compared to $6,202 (before elimination of intercompany drilling rig profit of $9.2 million) for all of 2010, an increase of 37% (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below).
1
The following table illustrates Unit’s drilling rig count at the end of each period and average utilization rate during the period:
| 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | |
|
Rigs
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127 | 126 | 123 | 122 | 121 | 123 | 123 | 125 | 130 |
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Utilization
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65% | 63% | 60% | 58% | 59% | 54% | 47% | 40% | 28% |
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 2011 was the seventh consecutive quarter of increased per day operating margins. As the industry has continued to transition to drilling horizontal or directional wells, we have been able to respond to that demand by refurbishing our existing drilling rigs or adding new drilling rigs. Approximately 93% of our drilling rigs working today are drilling for oil or natural gas liquids (NGLs) and approximately 98% are drilling horizontal or directional wells. We recently entered into an agreement to build a new 1,500 horsepower, diesel-electric drilling rig to be used in North Dakota. The drilling rig will be under a three-year contract and should be completed during the second quarter of 2012. After year-end, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third party. On completion of the new drilling rig, we will have 128 drilling rigs in our fleet. Currently, 83 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 60 of those 83 drilling rigs. Of these contracts, 9 are up for renewal during the first quarter of 2012, 12 during the second quarter of 2012, 16 during the third quarter of 2012, seven during the fourth quarter of 2012, and 16 in 2013 and beyond. These contracts do not include the term contract for the new drilling rig.”
OIL AND NATURAL GAS SEGMENT INFORMATION
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·
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During 2011, Unit’s oil and NGLs reserves increased 16% and 37%, respectively.
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·
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Replaced 202% of 2011 production with new reserve additions, of which 141% was through the drill bit.
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·
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Total production for 2011 was 12.1 MMBoe, an increase of 23% over 2010, and included an increase in oil and NGLs production of 55%.
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·
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Production guidance for 2012 is 13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011.
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Fourth quarter 2011 oil production was 744,000 barrels, as compared to 519,000 barrels for the same period of 2010, an increase of 43%. Natural gas liquids (NGLs) production during the fourth quarter of 2011 was 616,000 barrels, an increase of 52% when compared to 406,000 barrels for the same period of 2010. Fourth quarter 2011 natural gas production increased 7% to 11.4 billion cubic feet (Bcf) compared to 10.6 Bcf for the comparable quarter of 2010. Fourth quarter 2011 equivalent production averaged 35.4 MBoe per day, an increase of 21% over the fourth quarter of 2010 and an increase of 4% over the third quarter of 2011. Total production for 2011 was 12.1 MMBoe, an increase of 23% over the 9.9 MMBoe produced during 2010.
Unit’s average natural gas price, including the effects of hedges, for the fourth quarter of 2011 decreased 24% to $4.09 per thousand cubic feet (Mcf) as compared to $5.39 per Mcf for the fourth quarter of 2010. Unit’s average oil price, including the effects of hedges, for the fourth quarter of 2011 was $88.06 per barrel compared to $74.28 per barrel for the fourth quarter of 2010, an increase of 19%, and Unit’s average NGLs price, including the effects of hedges, for the fourth quarter of 2011 was $43.47 per barrel compared to $40.16 per barrel for the fourth quarter of 2010, an increase of 8%.
For 2011, Unit’s average natural gas price, including the effects of hedges, decreased 24% to $4.26 per Mcf as compared to $5.62 per Mcf for 2010. Unit’s average oil price, including the effects of hedges, for 2011 was $87.18 per barrel compared to $69.52 per barrel for 2010, a 25% increase. Unit’s average NGLs price, including the effects of hedges, for 2011 was $43.64 per barrel compared to $37.04 per barrel during 2010, an 18% increase.
For 2012, Unit has hedged approximately 50,000 MMBtu per day of its natural gas production and approximately 6,100 Bbls per day of its oil production. Unit has also hedged 1,966 Bbls per day of its first quarter NGLs production, 926 Bbls per day of its second quarter NGLs production, 380 Bbls per day of its third quarter NGLs production and 380 Bbls per day of its fourth quarter NGLs production. The natural gas production is hedged under swap contracts at an average price of $5.01 per MMBtu. The oil production is hedged under swap contracts at an average price of $97.55 per barrel. The NGLs production is hedged under swap contracts at an average price of $42.53 per barrel for the first quarter, $41.15 per barrel for the second quarter, $51.28 per barrel for the third quarter and $50.28 per barrel for the fourth quarter.
For 2013, Unit has hedged 3,000 Bbls per day of its oil production. The oil production is hedged under swap contracts at an average price of $101.91 per barrel.
2
The following table illustrates certain results for the periods indicated:
| 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | |
| Oil and NGL Production, MBo | 1,359.9 | 1,197.5 | 1,158.6 | 1,034.0 | 925.5 | 756.5 | 708.6 | 679.4 | 641.0 |
| Natural Gas Production, Bcf | 11.4 | 11.6 | 10.9 | 10.2 | 10.6 | 10.4 | 9.7 | 10.0 | 10.5 |
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Production, MBoe
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3,255 | 3,123 | 2,983 | 2,739 | 2,698 | 2,478 | 2,325 | 2,352 | 2,389 |
| Production, MBoe/day | 35.4 | 33.9 | 32.8 | 30.4 | 29.3 | 27.0 | 25.6 | 26.1 | 26.0 |
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Realized Price, Boe (1)
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$42.65 | $41.75 | $42.23 | $40.00 | $41.58 | $38.16 | $38.22 | $40.92 | $36.72 |
(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
Pinkston said: “We are pleased with the results from our exploration operations. The fourth quarter marks the eighth consecutive quarter that liquids (oil and NGLs) production has increased. Our strategy of drilling oil or NGLs rich wells is evident in our 2011 production results. Liquids production represented 42% and 34% of total equivalent production and 67% and 49% of this segment’s revenues during the fourth quarter of 2011 and 2010, respectively. Total equivalent production increased 23% to 12.1 MMBoe over 2010, while our total liquids production for 2011 increased 55% over 2010. Our total proved oil and natural gas reserves at December 31, 2011 were 116.0 MMBoe, a 12% increase over our 2010 total proved reserves. The reserve growth consisted of a 16% and 37% increase in oil and NGLs, respectively, while natural gas reserves increased 5%. Our production replacement for 2011 was 202%, with 141% through the drill bit. Our preliminary annual production guidance for 2012 is approximately 13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011.”
MID-STREAM SEGMENT INFORMATION
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Increased 2011 liquids sold per day volumes, processing volumes per day, and gathering volumes per day by 52%, 41% and 17%, respectively, over 2010.
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Completed construction of 16-mile, 16” pipeline and related compressor station in Preston County, West Virginia. The system is currently flowing 6 MMcf per day.
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Due to high level of activity around the Hemphill facility in Texas, a 45 MMcf per day gas processing plant will be installed with completion anticipated during second quarter of 2012.
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Fourth quarter of 2011 per day processing volumes were 156,721 MMBtu while liquids sold volumes were 511,410 gallons per day, an increase of 84% and 76%, respectively, over the fourth quarter of 2010. Fourth quarter 2011 per day gathering volumes were 257,398 MMBtu, an increase of 37% over the fourth quarter of 2010. Operating profit (as defined in the Selected Financial and Operational Highlights) for the fourth quarter was $7.7 million, a decrease of 22% from the fourth quarter of 2010, due primarily to renegotiated contracts with customers at one of our processing plants whereby the contracts changed from percent of index to percent of proceeds. Compared to the third quarter of 2011, operating profit increased 4% primarily due to increased volumes.
For 2011, processing volumes of 116,161 MMBtu per day and liquids sold volumes of 412,064 gallons per day increased 41% and 52%, respectively, over 2010. Gathering volumes for 2011 were 215,805 MMBtu per day, a 17% increase over 2010.
The following table illustrates certain results from this segment’s operations for the periods indicated:
| 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | |
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Gas gathered
MMBtu/day
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257,398 | 228,247 | 190,921 | 185,730 | 188,252 | 183,161 | 183,858 | 180,117 | 177,145 |
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Gas processed
MMBtu/day
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156,721 | 129,820 | 90,737 | 86,445 | 85,195 | 84,175 | 82,699 | 76,513 | 77,501 |
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Liquids sold
Gallons/day
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511,410 | 449,604 | 356,484 | 328,333 | 291,186 | 260,519 | 279,736 | 253,707 | 263,668 |
3
Pinkston said: “With the demand we are seeing in the industry for additional mid-stream infrastructure, we should continue to experience exciting growth opportunities for this segment.”
FINANCIAL INFORMATION
Unit ended the year with working capital of $15.7 million, long-term debt of $300.0 million ($250 million of senior subordinated notes and $50.0 million under its senior credit agreement), and a debt to capitalization ratio of 13%. Under its credit agreement, the amount available for Unit to borrow is the lesser of the amount Unit elects as the commitment amount (currently $250 million) or the value of the borrowing base as determined by the lenders (currently $600 million), but in either event not to exceed the maximum credit facility amount of $750 million.
MANAGEMENT COMMENT
Pinkston said: “We are pleased with our 2011 fourth quarter and the positive momentum each of our business segments carries into 2012. While we plan for growth in all three of our business segments, we are monitoring the potential impacts that current low natural gas prices may have on our operations as well as our customers. In response to these current natural gas prices, we may act to curtail up to 20 MMcf per day, or 16%, of our current daily natural gas production, or 9% of our total equivalent production. Any curtailment could result in subsequent changes to our 2012 preliminary production guidance, depending on the amount of the curtailment and how long we elect to curtail our production. Changing commodity prices, including any reductions in current oil and NGLs prices, may also result in modifications to our 2012 capital expenditures budget; however, decisions on any changes are not anticipated until after the first quarter of 2012. As we monitor natural gas prices, we will remain focused on the opportunities each of our business segments have for high-return projects. We will continue to focus our exploration operations on oil and natural gas liquids rich plays like the Granite Wash and Marmaton formations. Our contract drilling operations 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 developing 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 21, 2012 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 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.
4
Unit Corporation
Selected Financial and Operations Highlights
(In thousands except per share and operations data)
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Three Months Ended
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Twelve Months Ended
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|||||||||||
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December 31,
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December 31,
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2011
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2010
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2011
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2010
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Statement of Operations:
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Revenues:
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Contract drilling
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$
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142,553
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$
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98,465
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$
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484,651
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$
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316,384
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Oil and natural gas
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139,923
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114,056
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516,316
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400,807
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Gas gathering and processing
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63,418
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39,608
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208,238
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154,516
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Other, net
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(268
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)
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447
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(834
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)
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10,138
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Total revenues
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345,626
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252,576
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1,208,371
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881,845
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Expenses:
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Contract drilling:
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Operating costs
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79,813
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53,966
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269,899
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186,813
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Depreciation
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22,334
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21,270
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79,667
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69,970
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Oil and natural gas:
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Operating costs
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37,475
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29,422
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131,271
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105,365
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Depreciation, depletion
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and amortization
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51,337
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37,047
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183,350
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118,793
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Gas gathering and processing:
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Operating costs
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55,716
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29,739
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174,859
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122,146
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Depreciation
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and amortization
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4,474
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3,639
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16,101
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15,385
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General and administrative
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7,867
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6,780
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30,055
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26,152
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Interest, net
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2,089
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---
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4,167
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---
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Total expenses
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261,105
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181,863
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889,369
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644,624
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Income Before Income Taxes
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84,521
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70,713
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319,002
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237,221
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Income Tax Expense (Benefit):
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Current
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1,533
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(7,447
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)
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(2,416
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)
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(9,935
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)
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Deferred
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31,327
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34,495
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125,551
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100,672
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Total income taxes
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32,860
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27,048
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123,135
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90,737
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Net Income
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$
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51,661
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$
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43,665
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$
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195,867
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$
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146,484
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Net Income per Common Share:
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Basic
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$
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1.08
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$
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0.92
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$
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4.11
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$
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3.10
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Diluted
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$
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1.08
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$
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0.92
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$
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4.08
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$
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3.09
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Weighted Average Common
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||||||||||||
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Shares Outstanding:
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||||||||||||
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Basic
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47,703
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47,457
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47,658
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47,278
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Diluted
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48,028
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47,678
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47,951
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47,454
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5
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December 31,
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December 31,
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2011
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2010
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Balance Sheet Data:
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Current assets
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$
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228,465
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$
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188,180
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|||||
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Total assets
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$
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3,256,720
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$
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2,669,240
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Current liabilities
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$
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212,750
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$
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147,128
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|||||
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Long-term debt
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$
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300,000
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$
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163,000
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|||||
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Other long-term liabilities
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$
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113,830
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$
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92,389
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|||||
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Deferred income taxes
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$
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683,123
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$
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556,106
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|||||
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Shareholders’ equity
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$
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1,947,017
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$
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1,710,617
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|||||
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Twelve Months Ended December 31,
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|||||||||
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2011
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2010
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||||||||
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Statement of Cash Flows Data:
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|||||||||
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Cash Flow From Operations before Changes
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|||||||||
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in Operating Assets and Liabilities (1)
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$
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618,746
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$
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454,492
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|||||
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Net Change in Operating Assets and Liabilities
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(10,291
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)
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(64,420
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)
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|||||
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Net Cash Provided by Operating Activities
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$
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608,455
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$
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390,072
|
|||||
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Net Cash Used in Investing Activities
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$
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(768,236
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)
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$
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(536,261
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)
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|||
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Net Cash Provided by
Financing Activities
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$
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159,257
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$
|
146,408
|
|||||
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||
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December 31,
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December 31,
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|||||||||||
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2011
|
2010
|
2011
|
2010
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|||||||||
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Contract Drilling Operations Data:
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||||||||||||
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Rigs Utilized
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82.1
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70.9
|
76.1
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61.4
|
||||||||
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Operating Margins (2)
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44%
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45%
|
44%
|
41%
|
||||||||
|
Operating Profit Before Depreciation (2) ($MM)
|
$
|
62.7
|
$
|
44.4
|
$
|
214.8
|
$
|
129.6
|
||||
|
Oil and Natural Gas Operations Data:
|
||||||||||||
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Production:
|
||||||||||||
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Oil – MBbls
|
744
|
519
|
2,511
|
1,521
|
||||||||
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Natural Gas Liquids - MBbls
|
616
|
406
|
2,239
|
1,549
|
||||||||
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Natural Gas - MMcf
|
11,374
|
10,635
|
44,104
|
40,756
|
||||||||
|
Average Prices:
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||||||||||||
|
Oil price per barrel received
Oil price per barrel received, excluding hedges
|
$
$
|
88.06
92.88
|
$
$
|
74.28
81.56
|
$
$
|
87.18
93.49
|
$
$
|
69.52
76.65
|
||||
|
NGLs price per barrel received
NGLs price per barrel received,
excluding hedges
|
$
$
|
43.47
43.85
|
$
$
|
40.16
40.59
|
$
$
|
43.64
44.44
|
$
$
|
37.04
36.96
|
||||
|
Natural Gas price per Mcf received
Natural Gas price per Mcf received,
excluding hedges
|
$
$
|
4.09
3.29
|
$
$
|
5.39
3.41
|
$
$
|
4.26
3.78
|
$
$
|
5.62
4.05
|
||||
|
Operating Profit Before DD&A (2) ($MM)
|
$
|
102.4
|
$
|
84.6
|
$
|
385.0
|
$
|
295.4
|
||||
|
Mid-Stream Operations Data:
|
||||||||||||
|
Gas Gathering - MMBtu/day
|
257,398
|
188,252
|
215,805
|
183,867
|
||||||||
|
Gas Processing - MMBtu/day
|
156,721
|
85,195
|
116,161
|
82,175
|
||||||||
|
Liquids Sold – Gallons/day
|
511,410
|
291,186
|
412,064
|
271,360
|
||||||||
|
Operating Profit Before Depreciation
|
||||||||||||
|
and Amortization (2) ($MM)
|
$
|
7.7
|
$
|
9.9
|
$
|
33.4
|
$
|
32.4
|
||||
_____________
(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 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 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 and bad debt expense.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2011 and 2010. 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 Cash Flow From Operations Before Changes in Operating Assets and Liabilities
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Twelve Months Ended
December 31,
|
|||||||||
|
2011
|
2010
|
||||||||
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(In thousands)
|
|||||||||
|
Net cash provided by operating activities
|
$
|
608,455
|
$
|
390,072
|
|||||
|
Subtract:
|
|||||||||
|
Net change in operating assets and liabilities
|
10,291
|
64,420
|
|||||||
|
Cash flow from operations before changes
|
|||||||||
|
in operating assets and liabilities
|
$
|
618,746
|
$
|
454,492
|
|||||
________________
We have included the cash flow from operations before changes in operating assets and liabilities because:
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·
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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.
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|
·
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It is used by investors and financial analysts to evaluate the performance of our company.
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Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||||||
|
September 30,
|
December 31,
|
December 31,
|
||||||||||||||
|
2011
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Contract drilling revenue
|
$
|
128,927
|
$
|
142,553
|
$
|
98,465
|
$
|
484,651
|
$
|
316,384
|
||||||
|
Contract drilling operating cost
|
73,004
|
79,813
|
53,966
|
269,899
|
186,813
|
|||||||||||
|
Operating profit from contract drilling
|
55,923
|
62,740
|
44,499
|
214,752
|
129,571
|
|||||||||||
|
Add:
Elimination of intercompany rig profit
and bad debt expense
|
4,820
|
4,945
|
4,440
|
19,900
|
9,158
|
|||||||||||
|
Operating profit from contract drilling
|
||||||||||||||||
|
before elimination of intercompany
|
||||||||||||||||
|
rig profit and bad debt expense
|
60,743
|
67,685
|
48,939
|
234,652
|
138,729
|
|||||||||||
|
Contract drilling operating days
|
7,220
|
7,490
|
6,474
|
27,619
|
22,367
|
|||||||||||
|
Average daily operating margin before
|
||||||||||||||||
|
elimination of intercompany rig profit
and bad debt expense
|
$
|
8,413
|
$
|
9,037
|
$
|
7,559
|
$
|
8,496
|
$
|
6,202
|
||||||
________________
We have included the average daily operating margin before elimination of intercompany rig profit and bad debt expense 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.
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