Attached files
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| 8-K - 8-K - UNIT CORP | form8-k_2q14.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…
August 5, 2014
UNIT CORPORATION REPORTS 2014 SECOND QUARTER RESULTS
Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported its financial and operational results for the second quarter of 2014. Highlights for the quarter include:
• | Revenue of $405.4 million, an increase of 19% over the second quarter of 2013. |
• | Oil and natural gas segment’s total equivalent production increased 12% and 10% over the second quarter of 2013 and the first quarter of 2014, respectively. |
• | Oil and natural gas liquids (NGLs) production increased 18% and 13% over the second quarter of 2013 and the first quarter of 2014, respectively. |
• | Five additional BOSS drilling rigs now under contract to be built for third party operators. All of the rigs are expected to be placed into service during the balance of 2014 and early 2015. |
• | Average drilling rigs working increased 5.6 drilling rigs over the first quarter of 2014. |
• | Midstream segment’s per day gas gathered volumes and liquids sold volumes both increased 7% over the first quarter of 2014. |
Net income for the quarter was $54.4 million, or $1.11 per diluted share, compared to $59.0 million, or $1.22 per diluted share, for the second quarter of 2013. Adjusted net income for the quarter, which excludes the effect of non-cash commodity derivatives, was $55.4 million, or $1.13 per diluted share, compared to $48.8 million, or $1.01 per diluted share, for the same period in 2013 (see Non-GAAP Financial Measures below). Total revenues for the quarter were $405.4 million (49% oil and natural gas, 28% contract drilling, and 23% mid-stream), compared to $340.4 million (48% oil and natural gas, 31% contract drilling, and 21% mid-stream) for the second quarter of 2013.
Net income for the six months ended June 30, 2014 was $111.3 million, or $2.27 per diluted share, compared to $99.2 million, or $2.05 per diluted share, for the first six months of 2013. Adjusted net income for the first six months of 2014, which excludes the effect of non-cash commodity derivatives, was $118.1 million, or $2.41 per diluted share compared to $99.2 million, or $2.05 per diluted share, for the same period in 2013 (see Non-GAAP Financial Measures below). Total revenues for the first six months of 2014 were $793.4 million (49% oil and natural gas, 28% contract drilling, and 23% mid-stream), compared to $659.0 million (48% oil and natural gas, 32% contract drilling, and 20% mid-stream) for the first six months of 2013.
OIL AND NATURAL GAS SEGMENT INFORMATION
Total equivalent production for the quarter was 4.6 million barrels of oil equivalent (MMBoe), an increase of 12% over the second quarter of 2013 and a 10% increase over the first quarter of 2014. Liquids (oil and NGLs) production represented 46% of total equivalent production for the quarter. Oil production for the quarter was 10,400 barrels per day, an increase of 11% over the second quarter of 2013 and an increase of 16% over the first quarter of 2014. NGLs production for the quarter was 12,800 barrels per day, an increase of 24% over the second quarter of 2013 and an increase of 8% over the first quarter of 2014. Natural gas production for the quarter was 165,100 thousand cubic feet (Mcf) per day, an increase of 8% over the second quarter of 2013 and an increase of 7% over the first quarter of 2014. Total production for the first six months of 2014 was 8.8 MMBoe.
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For 2014, Unit has derivative contracts covering 7,000 Bbls per day of oil production and 90,000 MMBtu per day of natural gas production. The contracts for the oil production are swap contracts covering 3,000 Bbls per day and collars for 4,000 Bbls per day. The swap transactions are at a comparable average NYMEX price of $91.77. The collar transactions are at a comparable average NYMEX floor price of $90.00 and ceiling price of $96.08. The contracts for natural gas production are swaps covering 80,000 MMBtu per day and a collar covering 10,000 MMBtu per day. The swap transactions are at a comparable average NYMEX price of $4.24. The collar transaction is at a comparable average NYMEX floor price of $3.75 and ceiling price of $4.37.
For 2015, Unit has a derivative contract covering 1,000 Bbls per day of oil production. This swap transaction is at a comparable average NYMEX price of $95.00.
The following table illustrates this segment's comparative production, realized prices and operating profit for the periods indicated:
Three Months Ended | Three Months Ended | Six Months Ended | ||||||||||||||||||||||||
June 30, 2014 | March 31, 2014 | Change | June 30, 2014 | June 30, 2013 | Change | June 30, 2014 | June 30, 2013 | Change | ||||||||||||||||||
Oil and NGLs Production, MBbl | 2,113 | 1,875 | 13 | % | 2,113 | 1,794 | 18 | % | 3,989 | 3,395 | 18 | % | ||||||||||||||
Natural Gas Production, Bcf | 15.0 | 13.9 | 8 | % | 15.0 | 13.9 | 8 | % | 28.9 | 28.1 | 3 | % | ||||||||||||||
Production, MBoe | 4,618 | 4,184 | 10 | % | 4,618 | 4,109 | 12 | % | 8,802 | 8,079 | 9 | % | ||||||||||||||
Production, Mboe/day | 50.7 | 46.5 | 9 | % | 50.7 | 45.2 | 12 | % | 48.6 | 44.6 | 9 | % | ||||||||||||||
Avg. Realized Natural Gas Price, Mcfe (1) | $ | 4.05 | $ | 4.24 | (4 | )% | $ | 4.05 | $ | 3.65 | 11 | % | $ | 4.14 | $ | 3.47 | 19 | % | ||||||||
Avg. Realized NGLs Price, Bbl (1) | $ | 29.99 | $ | 39.56 | (24 | )% | $ | 29.99 | $ | 30.32 | (1 | )% | $ | 34.57 | $ | 32.47 | 6 | % | ||||||||
Avg. Realized Oil Price, Bbl (1) | $ | 94.17 | $ | 91.53 | 3 | % | $ | 94.17 | $ | 94.89 | (1 | )% | $ | 92.95 | $ | 95.05 | (2 | )% | ||||||||
Realized Price/ Boe (1) | $ | 40.10 | $ | 41.84 | (4 | )% | $ | 40.10 | $ | 39.10 | 3 | % | $ | 40.93 | $ | 38.56 | 6 | % | ||||||||
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2) | $ | 153.8 | $ | 147.8 | 4 | % | $ | 153.8 | $ | 119.8 | 28 | % | $ | 301.6 | $ | 230.4 | 31 | % | ||||||||
(1) Realized price includes oil, natural gas liquids, natural gas, and associated derivatives.
(2) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.
Production increased in all five of Unit’s core areas during the quarter as compared to the first quarter. In the Mid Continent, which includes the Granite Wash, Hoxbar (SOHOT), Marmaton, and Mississippian formations, production increased approximately 10%, and in the SE Texas Wilcox formation production increased approximately 17%. At the end of the quarter, 15 Unit drilling rigs were operating as compared to 10 drilling rigs at the end of the first quarter. Currently, there are five drilling rigs in the Granite Wash, three in the SOHOT, two in the Wilcox, two in the Marmaton, one in the Mississippian, one in the Cleveland, and one in the Cherokee for a total of 15 drilling rigs. Unit expects to maintain between 14 and 16 drilling rigs for the remainder of 2014.
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In SOHOT, production increased 81% in the quarter as compared to the first quarter, primarily as a result of our first operated Marchand horizontal completion. The Unit operated GB Ranch #1 30H (80% working interest) has produced approximately 105,000 barrels of oil and 60 million cubic feet (MMcf) of gas in 115 days. Current production is approximately 600 barrels of oil per day and 400 Mcf per day. Two additional Unit operated horizontal Marchand wells located in the same section are currently being drilled and completed with anticipated first sales for both wells anticipated to occur in August. In the SOHOT Medrano, Unit recently completed the Cody #1-36H (58% working interest) at a daily peak rate of approximately 5.2 MMcf per day and 324 barrels of oil per day. The 30-day and 60-day initial rate was approximately 3.8 MMcf per day plus 240 barrels of oil per day and 3.5 MMcf per day plus 200 barrels of oil per day, respectively.
In the Granite Wash (GW) Buffalo Wallow field, Unit is continuing to optimize the production operations by testing several types of artificial lift on the initial nine horizontal wells. To date, the GW “C1” and “B” zones have yielded the best results. Three “C1” wells were completed on three separate pads in the field. The average peak daily rate for the three “C1” wells was approximately 7.0 MMcfe per day. The three wells had an average 30-day and 60-day initial rate of approximately 5.2 MMcfe per day and 4.6 MMcfe per day, respectively. The “C1" zone is estimated to contain approximately 51% liquids. The GW “B” zone currently has one completion. The peak daily production rate was approximately 7.1 MMcfe per day. The 30- and 60-day initial rate was approximately 6.1 MMcfe per day and 4.9 MMcfe per day, respectively. The “B” zone contains approximately 40% liquids. The GW “E” (3 wells), “F1” (1 well) and “D” (1 well) zones tested at initial 30-day average rates of approximately 4.0 MMcfe per day, 2.6 MMcfe per day and 2.0 MMcfe per day, respectively. Additional production history is needed for the “E”, “F1” and “D” to determine if these zones will be economic at current commodity prices. Currently, two drilling rigs are drilling in the Buffalo Wallow field, both on three well pads. One pad will target the “B”, “C1” and “G” zones with estimated first sales occurring in the fourth quarter. The second pad will test the “B”, “C1” and “A” zones with estimated first sales in the first quarter of 2015. The average completed well cost for a Buffalo Wallow well is approximately $6.0 million.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results of our exploration program. We have made good progress following a challenging first quarter. Production has begun to ramp up, which we expect to continue throughout the remainder of the year. Our prospect inventory continues to remain strong.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the quarter was 73.5, an increase of 13% over the second quarter of 2013, and an increase of 8% over the first quarter of 2014. Per day drilling rig rates for the quarter averaged $19,904, an increase of 2% over the second quarter of 2013 and 1% over the first quarter of 2014. Average per day operating margin for the quarter was $8,317 (before elimination of intercompany drilling rig profit and bad debt expense of $7.8 million). This compares to $7,597 (before elimination of intercompany drilling rig profit and bad debt expense of $3.7 million) for the second quarter of 2013, an increase of 9%, or $720. As compared to the first quarter of 2014 ($7,870 before elimination of intercompany drilling rig profit and bad debt expense of $5.3 million), second quarter 2014 operating margin increased 6% or $447 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP Financial Measures below).
For the first six months of 2014, Unit averaged 70.7 drilling rigs working, an increase of 7% over the 65.8 drilling rigs working during the first six months of 2013. Average per day operating margin for the first six months of 2014 was $8,104 (before elimination of intercompany drilling rig profit and bad debt expense of $13.1 million) as compared to $7,565 (before elimination of intercompany drilling rig profit and bad debt expense of $7.1 million) for the first six months of 2013, an increase of 7% (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP Financial Measures below).
Larry Pinkston said: “Drilling rig demand continued at a steady increase during the quarter. Almost all of our drilling rigs working today are drilling for oil or NGLs. With our first BOSS drilling rig added in the first quarter, our drilling fleet currently totals 118 drilling rigs. Of the 118 drilling rigs, we currently have 80 drilling rigs working under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 35 of the 80 drilling rigs. Of the 35 long term contracts, five are up for renewal in the third quarter, 12 in the fourth quarter, and 18 are up for renewal in 2015. Our first BOSS drilling rig, which originally was placed into service with our oil and natural gas segment, has now been contracted to a third party operator that plans to take delivery in the fourth quarter of 2014. Five additional BOSS drilling rigs have been contracted to be built for third party operators and are expected to be placed into service during the balance of 2014 and early 2015. Operator reception of this new drilling rig design has been very positive, and we are confident that we will procure additional contracts in the near future. We have modified our building schedule for the BOSS drilling rig with the objective of staying two drilling rigs ahead of contracts in place.”
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The following table illustrates certain comparative results from this segment’s operations for the periods indicated:
Three Months Ended | Three Months Ended | Six Months Ended | ||||||||||||||||||||||||
June 30, 2014 | March 31, 2014 | Change | June 30, 2014 | June 30, 2013 | Change | June 30, 2014 | June 30, 2013 | Change | ||||||||||||||||||
Rigs Utilized | 73.5 | 67.9 | 8 | % | 73.5 | 65.2 | 13 | % | 70.7 | 65.8 | 7 | % | ||||||||||||||
Operating Margins (1) | 42 | % | 40 | % | 5 | % | 42 | % | 39 | % | 8 | % | 41 | % | 39 | % | 5 | % | ||||||||
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1) | $ | 47.8 | $ | 42.8 | 12 | % | $ | 47.8 | $ | 41.4 | 15 | % | $ | 90.6 | $ | 82.9 | 9 | % | ||||||||
(1) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.
MID-STREAM SEGMENT INFORMATION
Per day liquids sold and processed volumes increased 50% and 17%, respectively, as compared to the second quarter of 2013. For the quarter per day gathered volumes were 326,028 Mcf, essentially unchanged from the second quarter of 2013. Compared to the first quarter of 2014, liquids sold and gathered volumes per day both increased 7%, while processed volumes per day increased 8%. Operating profit (as defined in the footnote below) for the quarter was $14.0 million, an increase of 27% over the second quarter of 2013 and an increase of 15% over the first quarter of 2014.
The following table illustrates certain comparative results from this segment’s operations for the periods indicated:
Three Months Ended | Three Months Ended | Six Months Ended | ||||||||||||||||||||||||
June 30, 2014 | March 31, 2014 | Change | June 30, 2014 | June 30, 2013 | Change | June 30, 2014 | June 30, 2013 | Change | ||||||||||||||||||
Gas Gathering, Mcf/day | 326,028 | 304,083 | 7 | % | 326,028 | 326,039 | — | % | 315,116 | 299,582 | 5 | % | ||||||||||||||
Gas Processing, Mcf/day | 161,509 | 150,042 | 8 | % | 161,509 | 138,130 | 17 | % | 155,807 | 134,016 | 16 | % | ||||||||||||||
Liquids Sold, Gallons/day | 762,205 | 712,225 | 7 | % | 762,205 | 508,189 | 50 | % | 737,353 | 464,483 | 59 | % | ||||||||||||||
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1) | $ | 14.0 | $ | 12.2 | 15 | % | $ | 14.0 | $ | 11.1 | 27 | % | $ | 26.2 | $ | 19.0 | 38 | % | ||||||||
(1) Operating profit before depreciation is calculated by taking operating revenues by segment less operating expenses excluding depreciation, depletion, amortization, impairment, general and administrative, and gain on disposition of assets. Operating margins are calculated by dividing operating profit by segment revenue.
Larry Pinkston said: “Our midstream segment continues to grow organically, connecting 44 additional wells during the second quarter. Despite not recovering all ethane during the quarter, our liquids sold volumes and gas processed volumes continue to increase with limited incremental capital expenditure.”
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $645.9 million (all consisting of Unit’s senior subordinated notes), and a debt to capitalization ratio of 22%. Unit had no borrowings under its credit agreement. Unit’s credit agreement provides that the amount Unit could borrow is the lesser of the amount it elects as the commitment amount (currently $500 million) or the value of its borrowing base as determined by the lenders (currently $900 million), but in either event not to exceed $900 million.
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WEBCAST
Unit will webcast its second quarter earnings conference call live over the Internet on August 5, 2014 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.
_____________________________________________________
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.
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Unit Corporation
Selected Financial and Operations Highlights
(In thousands except per share amounts)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Statement of Operations: | ||||||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas | $ | 198,498 | $ | 164,799 | $ | 386,705 | $ | 318,408 | ||||||||
Contract drilling | 114,278 | 105,005 | 220,878 | 212,533 | ||||||||||||
Gas gathering and processing | 92,655 | 70,617 | 185,836 | 128,012 | ||||||||||||
Total revenues | 405,431 | 340,421 | 793,419 | 658,953 | ||||||||||||
Expenses: | ||||||||||||||||
Oil and natural gas: | ||||||||||||||||
Operating costs | 44,723 | 44,994 | 85,138 | 88,032 | ||||||||||||
Depreciation, depletion, and amortization | 71,245 | 55,335 | 130,925 | 107,318 | ||||||||||||
Contract drilling: | ||||||||||||||||
Operating costs | 66,494 | 63,590 | 130,298 | 129,592 | ||||||||||||
Depreciation | 20,239 | 17,908 | 38,634 | 35,168 | ||||||||||||
Gas gathering and processing: | ||||||||||||||||
Operating costs | 78,648 | 59,557 | 159,608 | 108,967 | ||||||||||||
Depreciation and amortization | 10,109 | 8,214 | 19,700 | 15,370 | ||||||||||||
General and administrative | 10,600 | 9,679 | 20,237 | 18,352 | ||||||||||||
Gain on disposition of assets | (195 | ) | (3,483 | ) | (9,621 | ) | (3,399 | ) | ||||||||
Total operating expenses | 301,863 | 255,794 | 574,919 | 499,400 | ||||||||||||
Income from operations | 103,568 | 84,627 | 218,500 | 159,553 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest, net | (4,131 | ) | (4,591 | ) | (7,921 | ) | (8,152 | ) | ||||||||
Gain (loss) on derivatives | (10,709 | ) | 16,344 | (29,075 | ) | 10,420 | ||||||||||
Other | (49 | ) | (91 | ) | 71 | (157 | ) | |||||||||
Total other income (expense) | (14,889 | ) | 11,662 | (36,925 | ) | 2,111 | ||||||||||
Income before income taxes | 88,679 | 96,289 | 181,575 | 161,664 | ||||||||||||
Income tax expense: | ||||||||||||||||
Current | 8,475 | 2,117 | 18,270 | 4,634 | ||||||||||||
Deferred | 25,844 | 35,165 | 52,000 | 57,817 | ||||||||||||
Total income taxes | 34,319 | 37,282 | 70,270 | 62,451 | ||||||||||||
Net income | $ | 54,360 | $ | 59,007 | $ | 111,305 | $ | 99,213 | ||||||||
Net income per common share: | ||||||||||||||||
Basic | $ | 1.12 | $ | 1.22 | $ | 2.29 | $ | 2.06 | ||||||||
Diluted | $ | 1.11 | $ | 1.22 | $ | 2.27 | $ | 2.05 | ||||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 48,642 | 48,208 | 48,568 | 48,162 | ||||||||||||
Diluted | 49,116 | 48,506 | 49,010 | 48,491 | ||||||||||||
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June 30, | December 31, | |||||||
2014 | 2013 | |||||||
Balance Sheet Data: | ||||||||
Current assets | $ | 211,266 | $ | 212,031 | ||||
Total assets | $ | 4,277,682 | $ | 4,022,390 | ||||
Current liabilities | $ | 314,550 | $ | 243,573 | ||||
Long-term debt | $ | 645,925 | $ | 645,696 | ||||
Other long-term liabilities | $ | 169,122 | $ | 158,331 | ||||
Deferred income taxes | $ | 853,398 | $ | 801,398 | ||||
Shareholders’ equity | $ | 2,294,687 | $ | 2,173,392 | ||||
Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
Statement of Cash Flows Data: | ||||||||
Cash flow from operations before changes in operating assets and liabilities (1) | $ | 370,348 | $ | 317,098 | ||||
Net change in operating assets and liabilities | (44,820 | ) | 790 | |||||
Net cash provided by operating activities | $ | 325,528 | $ | 317,888 | ||||
Net cash used in investing activities | $ | (379,107 | ) | $ | (322,471 | ) | ||
Net cash provided by financing activities | $ | 36,064 | $ | 4,650 | ||||
Non-GAAP Financial Measures
Unit Corporation reports its financial results in accordance with generally accepted accounting principles (“GAAP”). The Company believes certain non-GAAP performance measures provide users of its financial information and its management additional meaningful information to evaluate the performance of the company.
This press release includes cash flow from operations before changes in operating assets and liabilities, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, and net income and earnings per share including only the effect of the cash settled commodity derivatives.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and six months ended June 30, 2014 and 2013. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP.
Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
Six Months Ended | ||||||||
June 30, | ||||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
Net cash provided by operating activities | $ | 325,528 | $ | 317,888 | ||||
Net change in operating assets and liabilities | 44,820 | (790 | ) | |||||
Cash flow from operations before changes in operating assets and liabilities | $ | 370,348 | $ | 317,098 | ||||
________________
The Company has included the cash flow from operations before changes in operating assets and liabilities because:
• | It is an accepted financial indicator used by its management and companies in the industry to measure the company’s ability to generate cash which is used to internally fund its business activities. |
• | It is used by investors and financial analysts to evaluate the performance of the 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 | Six Months Ended | |||||||||||||||||||
March 31, | June 30, | June 30, | ||||||||||||||||||
2014 | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
(In thousands except operating days and operating margins) | ||||||||||||||||||||
Contract drilling revenue | $ | 106,600 | $ | 114,278 | $ | 105,005 | $ | 220,878 | $ | 212,533 | ||||||||||
Contract drilling operating cost | 63,804 | 66,494 | 63,590 | 130,298 | 129,592 | |||||||||||||||
Operating profit from contract drilling | 42,796 | 47,784 | 41,415 | 90,580 | 82,941 | |||||||||||||||
Add: | ||||||||||||||||||||
Elimination of intercompany rig profit and bad debt expense | 5,313 | 7,808 | 3,686 | 13,121 | 7,095 | |||||||||||||||
Operating profit from contract drilling before elimination of intercompany rig profit | 48,109 | 55,592 | 45,101 | 103,701 | 90,036 | |||||||||||||||
Contract drilling operating days | 6,113 | 6,684 | 5,937 | 12,797 | 11,901 | |||||||||||||||
Average daily operating margin before elimination of intercompany rig profit and bad debt expense | $ | 7,870 | $ | 8,317 | $ | 7,597 | $ | 8,104 | $ | 7,565 | ||||||||||
________________
The Company has included the average daily operating margin before elimination of intercompany rig profit and bad debt expense because:
• | Its management uses the measurement to evaluate the cash flow performance of its 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 the company. |
Unit Corporation
Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands except earnings per share) | ||||||||||||||||
Adjusted net income: | ||||||||||||||||
Net income | $ | 54,360 | $ | 59,007 | $ | 111,305 | $ | 99,213 | ||||||||
(Gain) loss on derivatives not designated as hedges and hedge ineffectiveness (net of income tax) | 6,564 | (10,052 | ) | 17,822 | (6,408 | ) | ||||||||||
Settlement during the period of matured derivative contracts (net of income tax) | (5,567 | ) | (111 | ) | (11,005 | ) | 528 | |||||||||
Adjusted net income | $ | 55,357 | $ | 48,844 | $ | 118,122 | $ | 93,333 | ||||||||
Adjusted diluted earnings per share: | ||||||||||||||||
Diluted earnings per share | $ | 1.11 | $ | 1.22 | $ | 2.27 | $ | 2.05 | ||||||||
Diluted earnings per share from the (gain) loss on derivatives | 0.13 | (0.21 | ) | 0.37 | (0.13 | ) | ||||||||||
Diluted earnings per share from the settlements of matured derivative contracts | (0.11 | ) | — | (0.23 | ) | 0.01 | ||||||||||
Adjusted diluted earnings per share | $ | 1.13 | $ | 1.01 | $ | 2.41 | $ | 1.93 | ||||||||
________________
The Company has included the net income and diluted earnings per share including only the cash settled commodity derivatives because:
• | It uses 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. |
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