Attached files
| file | filename |
|---|---|
| 8-K - 8-K - UNIT CORP | form8-k_1q13.htm |
News | UNIT CORPORATION |
7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136 | |
Telephone 918 493-7700, Fax 918 493-7714 | |
Contact: | Michael D. Earl |
Vice President, Investor Relations | |
(918) 493-7700 | |
www.unitcorp.com | |
For Immediate Release…
May 7, 2013
UNIT CORPORATION REPORTS 2013 FIRST QUARTER RESULTS
Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported its financial and operational results for the first quarter of 2013. Highlights for the quarter include:
• | Adjusted non-GAAP net income for the first quarter was $44.5 million, or $0.92 per diluted share (see Non-GAAP Financial Measures below). |
• | Total production for first quarter was 4.0 million barrels of oil equivalent (MMBoe), an increase of 21% over the first quarter of 2012. |
• | Total liquids (oil and natural gas liquids) production for the first quarter of 2013 increased 16% over the comparable quarter of 2012. |
• | Average number of drilling rigs utilized during the first quarter of 2013 increased 4% over the fourth quarter of 2012. |
• | Mid-stream increased first quarter of 2013 gathered volumes per day and processed volumes per day by 27% and 5%, respectively, over the first quarter of 2012. |
Net income for the three months ended March 31, 2013 was $40.2 million, or $0.83 per diluted share, compared to $52.4 million, or $1.09 per diluted share, for the three months ended March 31, 2012. Net income included the effect of a $7.0 million ($4.3 million after tax) reduction in earnings from the unrealized value of commodity derivatives. Without this reduction, net income for the first quarter would have been $44.5 million, or $0.92 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the first quarter of 2013 were $318.5 million (48% oil and natural gas, 34% contract drilling, and 18% mid-stream), compared to $334.0 million (41% oil and natural gas, 42% contract drilling, and 17% mid-stream) for the first quarter of 2012.
OIL AND NATURAL GAS SEGMENT INFORMATION
Unit’s strategy of drilling oil or natural gas liquids (NGLs) rich wells is evident in its production results. Liquids production represented 40% of total equivalent production during the first quarter of 2013. First quarter of 2013 total equivalent production increased 21% over the first quarter of 2012 to 4.0 MMBoe, while total liquids production for the first quarter of 2013 increased 16% over the comparable quarter of 2012. Liquids production for the first quarter of 2013 has increased 117% since the first quarter of 2009 when Unit began focusing on increasing its liquids production. First quarter 2013 oil production was 797,000 barrels, in comparison to 720,000 barrels for the same period of 2012, an increase of 11%. NGLs production during the first quarter of 2013 was 804,000 barrels, an increase of 23% when compared to 656,000 barrels for the same period of 2012. First quarter 2013 natural gas production increased 25% to 14.2 billion cubic feet (Bcf) compared to 11.4 Bcf for the comparable quarter of 2012. Total production for the first quarter 2013 was 4.0 MMBoe, an increase of 21% over the 3.3 MMBoe produced during the first quarter of 2012.
1
Unit’s average natural gas price for the first quarter of 2013 decreased 2% to $3.30 per thousand cubic feet (Mcf) as compared to $3.36 per Mcf for the first quarter of 2012. Unit’s average oil price for the first quarter of 2013 decreased 1% to $95.23 per barrel compared to $95.81 per barrel for the first quarter of 2012. Unit’s average NGLs price for the first quarter of 2013 was $34.99 per barrel compared to $38.81 per barrel for the first quarter of 2012, a decrease of 10%. All prices reflected in this paragraph include the effects of hedges.
For 2013, Unit has hedged 8,330 Bbls per day of its oil production and 100,000 MMBtu per day of natural gas production. The oil production is hedged under swap contracts at an average price of $97.94 per barrel. Of the natural gas production, 80,000 MMBtu per day is hedged with swaps and 20,000 MMBtu per day is hedged with a collar. The swap transactions were done at a comparable average NYMEX price of $3.65. The collar transaction was done at a comparable average NYMEX floor price of $3.25 and ceiling price of $3.72.
Currently for 2014, Unit has hedged 4,000 Bbls per day of its oil production and 50,000 MMBtu per day of natural gas production. Of the oil production, 2,000 Bbls per day is hedged with swaps and 2,000 Bbls per day is hedged with collars. The swap transactions were done at an average price of $91.40. The collar transactions were done at an average floor price of $90.00 and ceiling price of $95.00. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $4.24 per MMBtu.
The following table illustrates Unit’s production and certain results for the periods indicated:
1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | |
Oil and NGL Production, MBbl | 1,600.6 | 1,694.1 | 1,545.8 | 1,460.2 | 1,375.2 | 1,359.9 | 1,197.5 | 1,158.6 | 1,034.0 |
Natural Gas Production, Bcf | 14.2 | 14.5 | 11.7 | 11.3 | 11.4 | 11.4 | 11.6 | 10.9 | 10.2 |
Production, MBoe | 3,971 | 4,115 | 3,498 | 3,341 | 3,275 | 3,255 | 3,123 | 2,983 | 2,739 |
Production, MBoe/day | 44.1 | 44.7 | 38.0 | 36.7 | 36.0 | 35.4 | 33.9 | 32.8 | 30.4 |
Realized Price, Boe (1) | $37.73 | $39.56 | $37.99 | $38.49 | $40.51 | $42.65 | $41.75 | $42.23 | $40.00 |
(1) Realized price includes oil, natural gas liquids, natural gas and associated hedges.
The development of the “Gilly” Lower Wilcox field located in southeast Texas with estimated gross resource reserves of 262 Bcfe (168 Bcfe net) is continuing as planned with one new field well completed during the first quarter. There have been six wells completed in the field with plans to drill up to four additional field wells this year, including Unit's first horizontal well in one of the lower Wilcox sands. Production from the “Gilly” field started in June 2011, and during the first quarter of 2013, the field averaged approximately 370 barrels of oil per day, 1,210 barrels of NGL's per day, and 14 MMcf per day, or an equivalent rate of approximately 23 MMcfe per day. During this early phase of field development we are allowing sufficient time for testing multiple sands and drilling new wells to determine the most cost effective way to develop the reserves. Approximately one mile north of the Gilly Field, Unit has discovered a new productive fault block with the completion of two recent wells. Further testing and additional drilling is scheduled for later this year to delineate the potential of the discovery. For 2013, Unit plans to run one to two Unit drilling rigs, drilling approximately 12 wells with an estimated working interest of 90% at an approximate net cost of $60 million.
In Unit's Mississippian play, located primarily in south central Kansas, the installation of the pipeline and processing infrastructure is currently underway and is estimated to be completed during the third quarter of 2013. Current plans are to resume drilling in the prospect during the third quarter and continue to work one or two drilling rigs for the remainder of 2013. Unit's initial Mississippian well had first production in May 2012 with an average 30 day peak rate of approximately 350 Boe per day consisting of approximately 92% oil and NGLs. Unit's second well was drilled approximately two miles from the initial well and came on line at the very end of 2012 with a 30 day peak rate of approximately 130 Boe per day consisting of approximately 86% oil and NGLs. The Mississippian interval in both wells appear similar in character and shows; however, the second well had a smaller fracture stimulation design, which does not appear to have been as effective as the larger fracture stimulation design on the initial well. Based on the production profile from both of these wells, the reserve range estimate remains at 125 MBoe to 180 MBoe. Unit currently has approximately 110,000 net acres in the Mississippian play and plans to spend approximately $40 million drilling and completing approximately 13 wells during 2013.
2
In the Marmaton horizontal oil play located in Beaver County, Oklahoma, Unit completed 10 wells during the first quarter with an average working interest of 74%. The average 30 day peak rate for first quarter wells was approximately 390 Boe, which is similar to 2012 results and in line with expectations. Development of the field is continuing on one well per 640 acre spacing and estimated ultimate reserves is unchanged from previous estimates of 120 MBoe to 130 MBoe per well Unit currently has leases on approximately 113,000 net acres in this play with approximately 47% of the leasehold held by production. For 2013, Unit anticipates running a two to three drilling rig program in this play that should result in approximately 40 gross wells at an approximate net cost of $90 million.
In its Granite Wash (GW) play located in the Texas Panhandle, Unit started 2013 with two Unit drilling rigs drilling and added a third and fourth drilling rig during the first quarter with current plans to add a fifth drilling rig in the third quarter and potentially a sixth drilling rig in the fourth quarter. Drilling operations on Unit's first horizontal GW well from the recent Noble acquisition began in March, and we expect to drill and test several different GW sands across the leasehold this year. For the first quarter 2013, Unit had first sales on four horizontal wells with a peak 30 day IP rate of 4.7 MMcfe per day at an average working interest of 97%. For 2013, Unit anticipates completing approximately 30 horizontal wells at an approximate net cost of $140 million.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results from our exploration operations, and we are excited about our opportunities for growth. Production was down slightly during the first quarter of 2013 from the fourth quarter of 2012 due principally to weather related issues and reducing the number of company operated drilling rigs to six during the fourth quarter of 2012. We began ramping up our drilling program during the first quarter of 2013. We are currently operating eight drilling rigs and plan to increase this number throughout 2013 depending on market conditions. Our continued focus on oil and liquids rich opportunities is anticipated to produce continued progress in our hydrocarbon mix during the year. Unit’s annual production guidance for 2013 is approximately 16.0 to 16.5 MMBoe, an increase of 13% to 16% over 2012.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the first quarter of 2013 was 66.3, a decrease of 19% from the first quarter of 2012, and an increase of 4% from the fourth quarter of 2012. Per day drilling rig rates for the first quarter of 2013 averaged $19,580, a decrease of 1%, or $258, from the first quarter of 2012, and a 1% decrease, or $248, from the fourth quarter of 2012. Average per day operating margin for the first quarter of 2013 was $7,534 (before elimination of intercompany drilling rig profit of $3.4 million). This compares to $9,414 (before elimination of intercompany drilling rig profit of $4.3 million) for the first quarter of 2012, a decrease of 20%, or $1,880. As compared to the fourth quarter of 2012 ($7,838 before elimination of intercompany drilling rig profit of $2.6 million), first quarter 2013 operating margin decreased 4% or $304 (in each case regarding the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below). For the first quarter and fourth quarter of 2012 average operating margins included early termination fees, approximately $95 per day and $24 per day, respectively, from the cancellation of certain long-term contracts.
Larry Pinkston said: “Drilling activity began to improve during the first quarter of 2013 as we’ve seen a slight increase in demand for our drilling rigs. We believe that operators are continuing to focus on shallower oil plays and liquids rich plays which provided the opportunity to put more of our 750 to 1,000 horsepower drilling rigs to work. Approximately 99% of our drilling rigs working today are drilling for oil or NGLs. Currently, we have 127 drilling rigs in our fleet, of which 66 are under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 27 of those 66 drilling rigs. Of these contracts, four are up for renewal during the second quarter of 2013, ten during the third quarter of 2013, two during the fourth quarter of 2013, and 11 in 2014 and beyond. During 2013, the drilling segment will be constructing a new prototype 1,500 horsepower AC electric drilling rig of proprietary design. The drilling rig will operate initially for our oil and natural gas segment when completed.”
The following table illustrates Unit’s drilling rig count at the end of each period and average utilization rate during the period:
1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | |
Rigs | 127 | 127 | 127 | 128 | 127 | 127 | 126 | 123 | 122 |
Utilization | 52% | 50% | 58% | 60% | 64% | 65% | 63% | 60% | 58% |
MID-STREAM SEGMENT INFORMATION
First quarter of 2013 per day gathered volumes were 318,834 MMBtu while per day processed volumes were 162,287 MMBtu, an increase of 27% and 5%, respectively, over the first quarter of 2012. Per day gathered and processed volumes decreased 2% and 1%, respectively, as compared to the fourth quarter of 2012. First quarter 2013 liquids sold volumes were 420,291 gallons per day, a decrease of 5% from the fourth quarter of 2012 and a decrease of 20% from first quarter 2012 primarily due to operating in ethane rejection mode and wells shut in during a snow storm in the first quarter of 2013. Operating profit (as defined in the Selected
3
Financial and Operational Highlights) for the first quarter of 2013 was $8.0 million, a decrease of 18% from the first quarter of 2012 and an increase of 24% from the fourth quarter of 2012.
The following table illustrates certain results from this segment’s operations for the periods indicated:
1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | |
Gas gathered MMBtu/day | 318,834 | 325,231 | 277,806 | 300,602 | 251,276 | 257,398 | 228,247 | 190,921 | 185,730 |
Gas processed MMBtu/day | 162,287 | 163,173 | 166,652 | 177,407 | 154,825 | 156,721 | 129,820 | 90,737 | 86,445 |
Liquids sold Gallons/day | 420,291 | 441,973 | 576,889 | 629,350 | 522,829 | 511,410 | 449,604 | 356,484 | 328,333 |
Larry Pinkston said: “In the Mississippian play in north central Oklahoma, we are continuing to expand our Bellmon system. In the first quarter of 2013, we added approximately 54 miles of gathering pipeline, which increases the total miles of pipeline to 136 for this system. Also during the first quarter of 2013, we completed the installation of our second processing plant at the Bellmon facility. With the installation of this new processing plant, our total processing capacity at this facility increased to 55 MMcf per day. At our Hemphill facility located in Hemphill County, Texas, we now have the capacity to process 140 MMcf per day of our own and third party Granite Wash natural gas production. Also at this facility, we are completing two pipeline extension projects for a total capital cost of approximately $5.7 million, which will allow us to connect additional production to our system from new areas. In Reno County, Kansas, we are in the process of constructing a new gathering system and processing plant. This facility is currently under construction and will consist initially of 35 miles of gathering pipeline and two processing plants, an 8 MMcf per day refrigeration plant and a 20 MMcf per day turbo expander plant. This system is designed to gather and process our gas as well as third party production in the area.”
“In the Appalachian area, we are continuing to expand our Pittsburgh Mills gathering system which is located in Allegheny County, Pennsylvania. We have completed the 1st phase of this project which consists of approximately seven miles of gathering pipeline and the related compressor station at which we have installed four rental compressors. We are continuing to connect third party wells to this system. We have 14 wells connected to this system with four additional wells scheduled to be connected in the second quarter of 2013. The total gathered volume from the wells currently connected to our system is approximately 50 MMcf per day. Construction activity for expansion of this gathering system continues as the producer is maintaining its level of drilling activity.”
FINANCIAL INFORMATION
Unit ended the first quarter with long-term debt of $715.4 million ($645.4 million of senior subordinated notes and $70.0 million under its credit agreement), and a debt to capitalization ratio of 26%. Under its credit agreement, the amount available for Unit to borrow is the lesser of the amount Unit elects as the commitment amount (currently $500 million) or the value of its borrowing base as determined by the lenders (currently $800 million), but in either event not to exceed the maximum amount of $900 million.
MANAGEMENT COMMENT
Larry Pinkston said: “We are pleased with the results of our operations in all three segments and are excited about the growth opportunities for 2013. The recent acquisition from Noble was an important growth step for us going forward. We plan to accelerate the drilling activity in the acquired properties and our other Granite Wash acreage over the next 12 to 18 months using up to six rigs from our contract drilling segment, and we plan to operate the acquired gathering systems and replace existing third party processing contracts beginning in 2015. Unit continues to maintain a conservative financial profile. As a result, we are well positioned to take advantage of growth opportunities that may arise for our business segments.”
WEBCAST
Unit will webcast its first quarter earnings conference call live over the Internet on May 7, 2013 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm at least fifteen minutes prior to the start of the call to download and install any necessary audio software. For those who are not available to listen to the live webcast, a replay will be available shortly after the call and will remain on the site for 90 days.
4
_____________________________________________________
Unit Corporation is a Tulsa-based, publicly held energy company engaged through its subsidiaries in oil and gas exploration, production, contract drilling and gas gathering and processing. Unit’s Common Stock is on the New York Stock Exchange under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.
FORWARD-LOOKING STATEMENT
This news release contains forward-looking statements within the meaning of the private Securities Litigation Reform Act. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the company expects or anticipates will or may occur in the future are forward-looking statements. Several risks and uncertainties could cause actual results to differ materially from these statements, including the productive capabilities of the company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected growth of the company’s oil and natural gas production, oil and gas reserve information, and its ability to meet its future reserve replacement goals, anticipated gas gathering and processing rates and throughput volumes, the prospective capabilities of the reserves associated with the company’s inventory of future drilling sites, anticipated oil and natural gas prices, the number of wells to be drilled by the company’s exploration segment, development, operational, implementation and opportunity risks, possible delays caused by limited availability of third party services needed in its operations, possibility of future growth opportunities, and other factors described from time to time in the company’s publicly available SEC reports. The company assumes no obligation to update publicly such forward-looking statements, whether because of new information, future events or otherwise.
5
Unit Corporation
Selected Financial and Operations Highlights
(In thousands except per share and operations data)
Three Months Ended | ||||||||
March 31, | ||||||||
2013 | 2012 | |||||||
Statement of Operations: | ||||||||
Revenues: | ||||||||
Oil and natural gas | $ | 153,609 | $ | 135,765 | ||||
Contract drilling | 107,528 | 140,906 | ||||||
Gas gathering and processing | 57,395 | 57,295 | ||||||
Total revenues | 318,532 | 333,966 | ||||||
Expenses: | ||||||||
Oil and natural gas: | ||||||||
Operating costs | 43,038 | 35,609 | ||||||
Depreciation, depletion, and amortization | 51,983 | 52,197 | ||||||
Contract drilling: | ||||||||
Operating costs | 66,002 | 76,173 | ||||||
Depreciation | 17,260 | 21,328 | ||||||
Gas gathering and processing: | ||||||||
Operating costs | 49,410 | 47,613 | ||||||
Depreciation and amortization | 7,156 | 5,134 | ||||||
General and administrative | 8,673 | 7,004 | ||||||
Total operating expenses | 243,522 | 245,058 | ||||||
Income from operations | 75,010 | 88,908 | ||||||
Other income (expense): | ||||||||
Interest, net | (3,561 | ) | (1,826 | ) | ||||
Loss on derivatives | (5,924 | ) | (1,993 | ) | ||||
Other | (150 | ) | 455 | |||||
Total other income (expense) | (9,635 | ) | (3,364 | ) | ||||
Income before income taxes | 65,375 | 85,544 | ||||||
Income tax expense: | ||||||||
Current | 2,517 | — | ||||||
Deferred | 22,652 | 33,105 | ||||||
Total income taxes | 25,169 | 33,105 | ||||||
Net income | $ | 40,206 | $ | 52,439 | ||||
Net income per common share: | ||||||||
Basic | $ | 0.84 | $ | 1.10 | ||||
Diluted | $ | 0.83 | $ | 1.09 | ||||
Weighted average shares outstanding: | ||||||||
Basic | 48,117 | 47,829 | ||||||
Diluted | 48,412 | 48,126 | ||||||
6
March 31, | December 31, | |||||||
2013 | 2012 | |||||||
Balance Sheet Data: | ||||||||
Current assets | $ | 189,575 | $ | 195,644 | ||||
Total assets | $ | 3,814,840 | $ | 3,761,120 | ||||
Current liabilities | $ | 212,454 | $ | 207,139 | ||||
Long-term debt | $ | 715,365 | $ | 716,359 | ||||
Other long-term liabilities | $ | 158,510 | $ | 167,545 | ||||
Deferred income taxes | $ | 718,498 | $ | 695,776 | ||||
Shareholders’ equity | $ | 2,010,013 | $ | 1,974,301 | ||||
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Statement of Cash Flows Data: | ||||||||
Cash flow from operations before changes in operating assets and liabilities (1) | $ | 153,314 | $ | 170,876 | ||||
Net change in operating assets and liabilities | 26,346 | (22,929 | ) | |||||
Net cash provided by operating activities | $ | 179,660 | $ | 147,947 | ||||
Net cash used in investing activities | $ | (191,471 | ) | $ | (189,419 | ) | ||
Net cash provided by financing activities | $ | 11,990 | $ | 41,832 | ||||
Three Months Ended | ||||||||
March 31, | ||||||||
2013 | 2012 | |||||||
Oil and Natural Gas Operations Data: | ||||||||
Production: | ||||||||
Oil – MBbls | 797 | 720 | ||||||
NGLs - MBbls | 804 | 656 | ||||||
Natural gas - MMcf | 14,220 | 11,400 | ||||||
Average Prices: | ||||||||
Oil price per barrel received | $ | 95.23 | $ | 95.81 | ||||
Oil price per barrel received, excluding hedges | $ | 91.94 | $ | 100.16 | ||||
NGLs price per barrel received | $ | 34.99 | $ | 38.81 | ||||
NGLs price per barrel received, excluding hedges | $ | 34.99 | $ | 37.38 | ||||
Natural gas price per Mcf received | $ | 3.30 | $ | 3.36 | ||||
Natural gas price per Mcf received, excluding hedges | $ | 3.14 | $ | 2.45 | ||||
Operating profit before depreciation, depletion, and amortization (2) ($MM) | $ | 110.6 | $ | 98.2 | ||||
Contract Drilling Operations Data: | ||||||||
Rigs utilized | 66.3 | 81.5 | ||||||
Operating margins (2) | 39 | % | 46 | % | ||||
Operating profit before depreciation (2) ($MM) | $ | 41.5 | $ | 64.7 | ||||
Mid-Stream Operations Data: | ||||||||
Gas gathering - MMBtu/day | 318,834 | 251,276 | ||||||
Gas processing - MMBtu/day | 162,287 | 154,825 | ||||||
Liquids sold – gallons/day | 420,291 | 522,829 | ||||||
Operating profit before depreciation and amortization (2) ($MM) | $ | 8.0 | $ | 9.7 | ||||
(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, general and administrative and interest expense. Operating margins are calculated by dividing operating profit by segment revenue.
7
Non-GAAP Financial Measures
We report our financial results in accordance with generally accepted accounting principles (“GAAP”). We believe certain non-GAAP performance measures provide users of our financial information and our management additional meaningful information to evaluate the performance of our company.
This press release includes cash flow from operations before changes in operating assets and liabilities, our drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit, and net income and earnings per share excluding the effect of the unrealized value of commodity derivatives.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three months ended March 31, 2013 and 2012. Non-GAAP financial measures should not be considered by themselves or a substitute for our results reported in accordance with GAAP.
Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
Three Months Ended | ||||||||
March 31, | ||||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
Net cash provided by operating activities | $ | 179,660 | $ | 147,947 | ||||
Net change in operating assets and liabilities | (26,346 | ) | 22,929 | |||||
Cash flow from operations before changes in operating assets and liabilities | $ | 153,314 | $ | 170,876 | ||||
________________
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 | ||||||||||||
March 31, | December 31, | |||||||||||
2013 | 2012 | 2012 | ||||||||||
(In thousands except operating days and operating margins) | ||||||||||||
Contract drilling revenue | $ | 107,528 | $ | 140,906 | $ | 108,521 | ||||||
Contract drilling operating cost | 66,002 | 76,173 | 65,544 | |||||||||
Operating profit from contract drilling | 41,526 | 64,733 | 42,977 | |||||||||
Add: | ||||||||||||
Elimination of intercompany rig profit | 3,409 | 4,284 | 2,647 | |||||||||
Operating profit from contract drilling before elimination of intercompany rig profit | 44,935 | 69,017 | 45,624 | |||||||||
Contract drilling operating days | 5,964 | 7,331 | 5,821 | |||||||||
Average daily operating margin before elimination of intercompany rig profit | $ | 7,534 | $ | 9,414 | $ | 7,838 | ||||||
________________
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 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. |
8
Unit Corporation
Reconciliation of Net Income (Loss) and Diluted Earnings per Share
Excluding the Effect of the Unrealized Value of Commodity Derivatives
Three Months Ended | ||||||||
March 31, | ||||||||
2013 | 2012 | |||||||
(In thousands except earnings per share) | ||||||||
Net income excluding the unrealized value of commodity derivatives: | ||||||||
Net income | $ | 40,206 | $ | 52,439 | ||||
Add: | ||||||||
Unrealized value of commodity derivatives (net of income tax) | 4,283 | 1,222 | ||||||
Net income excluding the unrealized value of commodity derivatives | $ | 44,489 | $ | 53,661 | ||||
Diluted earnings per share excluding the unrealized value of commodity derivatives: | ||||||||
Diluted earnings per share | $ | 0.83 | $ | 1.09 | ||||
Add: | ||||||||
Diluted earnings per share from the unrealized value of commodity derivatives | 0.09 | 0.03 | ||||||
Diluted earnings per share excluding the unrealized value of commodity derivatives | $ | 0.92 | $ | 1.12 | ||||
________________
We have included the net income excluding the unrealized value of commodity derivatives and diluted earnings per share excluding the unrealized value of commodity derivatives 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. |
9