Unit Corporation (NYSE:UNT) today reported its financial and operational
results for the third quarter of 2014. Highlights include:
-
Revenue of $401.0 million, an increase of 20% over the third quarter
of 2013. -
Oil and natural gas segment’s total equivalent production increased 9%
over the third quarter of 2013. -
Oil and natural gas liquids (NGLs) production increased 19% and 4%
over the third quarter of 2013 and the second quarter of 2014,
respectively. -
Three additional BOSS drilling rigs contracted for third-party
operators. -
Average drilling rigs working increased 5.6 drilling rigs over the
second quarter of 2014. -
Midstream segment’s per day gas processed volumes and liquids sold
volumes increased 17% and 32%, respectively, over the third quarter of
2013.
Net income for the quarter was $67.5 million, or $1.37 per diluted
share, compared to $34.2 million, or $0.70 per diluted share, for the
third quarter of 2013. Adjusted net income for the quarter, which
excludes the effect of non-cash commodity derivatives, was $54.7
million, or $1.11 per diluted share, compared to $41.2 million, or $0.85
per diluted share, for the same period in 2013 (see Non-GAAP Financial
Measures below). Total revenues for the quarter were $401.0 million (47%
oil and natural gas, 30% contract drilling, and 23% mid-stream),
compared to $333.8 million (47% oil and natural gas, 30% contract
drilling, and 23% mid-stream) for the third quarter of 2013.
Net income for the nine months ended September 30, 2014 was $178.8
million, or $3.65 per diluted share, compared to $133.4 million, or
$2.75 per diluted share, for the first nine months of 2013. Adjusted net
income for the first nine months of 2014, which excludes the effect of
non-cash commodity derivatives, was $172.9 million, or $3.52 per diluted
share, compared to $134.5 million, or $2.77 per diluted share, for the
same period in 2013 (see Non-GAAP Financial Measures below). Total
revenues for the first nine months of 2014 were $1,194.4 million (48%
oil and natural gas, 29% contract drilling, and 23% mid-stream),
compared to $992.7 million (48% oil and natural gas, 32% contract
drilling, and 20% mid-stream) for the first nine 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 9% over the third quarter of 2013
and essentially unchanged compared to the second quarter of 2014. The
third quarter of 2014 production was negatively impacted by
approximately 0.5 billion cubic feet of natural gas equivalent (Bcfe)
due to a third-party plant being shut down in the Wilcox play for
approximately seven days. Liquids (oil and NGLs) production represented
47% of total equivalent production for the quarter. Oil production for
the quarter was 11,307 barrels per day, an increase of 28% over the
third quarter of 2013 and an increase of 8% over the second quarter of
2014. NGLs production for the quarter was 12,473 barrels per day, an
increase of 13% over the third quarter of 2013 and a decrease of 2% from
the second quarter of 2014. Natural gas production for the quarter was
158,075 thousand cubic feet (Mcf) per day, an increase of 2% over the
third quarter of 2013 and a decrease of 4% from the second quarter of
2014. Total production for the first nine months of 2014 was 13.4 MMBoe.
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:
|
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| Three Months Ended | Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| Sept. 30, | Sept. 30, | Sept. 30, | June 30, | Sept. 30, | Sept. 30, | |||||||||||||||||||
| 2014 | 2013 | Change | 2014 | 2014 | Change | 2014 | 2013 | Change | ||||||||||||||||
| Oil and NGLs Production, MBbl | 2,188 | 1,833 | 19% | 2,188 | 2,113 | 4% | 6,176 | 5,228 | 18% | |||||||||||||||
| Natural Gas Production, Bcf | 14.5 | 14.3 | 2% | 14.5 | 15.0 | (3)% | 43.4 | 42.4 | 2% | |||||||||||||||
| Production, MBoe | 4,612 | 4,217 | 9% | 4,612 | 4,618 | —% | 13,414 | 12,296 | 9% | |||||||||||||||
| Production, MBoe/day | 50.1 | 45.8 | 9% | 50.1 | 50.7 | (1)% | 49.1 | 45.0 | 9% | |||||||||||||||
| Avg. Realized Natural Gas Price, Mcfe (1) | $ | 3.68 | $ | 3.11 | 18% | $ | 3.68 | $ | 4.05 | (9)% | $ | 3.99 | $ | 3.35 | 19% | |||||||||
|
Avg. Realized NGL Price, Bbl (1) |
$ | 30.11 | $ | 28.10 | 7% | $ | 30.11 | $ | 29.99 | —% | $ | 33.05 | $ | 30.87 | 7% | |||||||||
|
Avg. Realized Oil Price, Bbl (1) |
$ | 91.57 | $ | 95.49 | (4)% | $ | 91.57 | $ | 94.17 | (3)% | $ | 92.44 | $ | 95.20 | (3)% | |||||||||
| Realized Price / Boe (1) | $ | 39.76 | $ | 35.77 | 11% | $ | 39.76 | $ | 40.10 | (1)% | $ | 40.53 | $ | 37.60 | 8% | |||||||||
|
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (2) |
$ | 139.6 | $ | 107.2 | 30% | $ | 139.6 | $ | 153.8 | (9)% | $ | 441.2 | $ | 337.6 | 31% | |||||||||
|
(1) Realized price includes oil, natural gas liquids, natural gas |
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|
(2) Operating profit before depreciation is calculated by taking |
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At the end of the quarter, 15 Unit drilling rigs were operating for our
exploration segment. Six were operating in the Granite Wash, three in
the Southern Oklahoma Hoxbar Oil Trend (SOHOT), two in the Wilcox, two
in the Marmaton, one in the Mississippian, and one in the Cherokee. Unit
anticipates that three of these drilling rigs will be released during
the fourth quarter, one in the Granite Wash, one in the Marmaton, and
one in the Cherokee.
In the SOHOT area, production increased 56% during the quarter as
compared to the second quarter of 2014, primarily because of two new
operated horizontal Marchand completions. The Unit Earl # 2-30H (80%
working interest) started producing on August 3, 2014. The 30-day,
60-day and 90-day initial rate for that well was approximately 1,581
barrels of oil equivalent (Boe) per day, 1,342 Boe per day, and 1,151
Boe per day, respectively. The second well, the Unit Rosey Havenstrite
#1H (80% working interest), started production on September 11, 2014.
The 30-day initial rate for that well was approximately 1,414 Boe per
day. The average production mix of the two wells is 86% oil, 4% NGLs,
and 10% natural gas. Currently, there are five new operated Hoxbar wells
scheduled to be fracture stimulated during the fourth quarter. The
majority of the production impact from these wells will not be realized
until the first quarter 2015.
In the Granite Wash (GW) Buffalo Wallow field, Unit recently
successfully fracture stimulated a three well pad (GW “B”, “C1” and “G”)
using an upsized frac design. The new design pumps approximately 4.4
million pounds of sand, an increase of approximately 80% over the
previous fracs in the field. The number of stages, perf clusters, and
concentration of 100 mesh sand has also been increased. First gas
production from the pad should start in mid-December. A second three
well pad (GW “B”, “C1” and “A”) is scheduled to be fracture stimulated
during the fourth quarter, also using the new frac design, with first
gas production scheduled for the first quarter of 2015.
In the Gilly Wilcox field, Unit completed the Jackson GU #1 (84% working
interest) from a previously untested shallower “Gilchrease” Wilcox sand.
The well had first gas sales on September 21st at a 30-day
unstimulated rate of approximately 1,022 Boe per day with approximately
5,600 psi of flowing casing pressure. The production stream is 12% oil,
37% NGLs, and 51% natural gas. The Gilchrease zone is present behind
pipe and appears productive in all 13 of the current Gilly field wells.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “For
our oil and natural gas segment, production was essentially unchanged
between the third quarter and second quarter of 2014, although third
quarter 2014 production was up 9% over the comparable quarter of 2013.
Delays in availability for fracture stimulation in the Wilcox, delays in
infrastructure completion in the Granite Wash, and delays in drilling
pilot holes in the SOHOT have slowed our anticipated rate of growth for
the year. As a result, we are revising our production guidance for 2014
to 9% to 10% growth over 2013, which anticipates production growth of at
least 4% in the fourth quarter 2014 over the third quarter 2014.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the quarter was 79.1, an
increase of 25% over the third quarter of 2013, and an increase of 8%
over the second quarter of 2014. Per day drilling rig rates for the
quarter averaged $20,070, an increase of 2% over the third quarter of
2013 and 1% over the second quarter of 2014. Average per day operating
margin for the quarter was $8,449 (before elimination of intercompany
drilling rig profit and bad debt expense of $7.6 million). This compares
to $7,920 (before elimination of intercompany drilling rig profit and
bad debt expense of $4.6 million) for the third quarter of 2013, an
increase of 7%, or $529. As compared to the second quarter of 2014
($8,317 before elimination of intercompany drilling rig profit and bad
debt expense of $7.8 million), third quarter 2014 operating margin
increased 2% or $132 (in each case regarding eliminating intercompany
drilling rig profit and bad debt expense – see Non-GAAP Financial
Measures below).
For the first nine months of 2014, Unit averaged 73.5 drilling rigs
working, an increase of 13% over the 65.0 drilling rigs working during
the first nine months of 2013. Average per day operating margin for the
first nine months of 2014 was $8,229 (before elimination of intercompany
drilling rig profit and bad debt expense of $20.7 million) as compared
to $7,682 (before elimination of intercompany drilling rig profit and
bad debt expense of $11.7 million) for the first nine 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. During the third quarter, our second BOSS
drilling rig began operating, and recently our third BOSS drilling rig
was delivered and began operating, bringing our fleet to a total of 120
drilling rigs. Of the 120 drilling rigs, we currently have 82 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 38 of the 82 drilling rigs. Of the 38 long term contracts, 14
are up for renewal in the fourth quarter, and 24 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 this month. Our
fourth BOSS drilling rig will be delivered later this quarter, and five
additional BOSS drilling rigs have been contracted to be built for
third-party operators and are expected to be placed into service during
2015. In addition, we have ordered the long lead time components for
three additional BOSS drilling rigs. Operator reception of this new
drilling rig design has been very positive, and we are pleased to have
more of them working in the field to demonstrate the advantages of this
new design.”
The following table illustrates certain comparative results from this
segment’s operations for the periods indicated:
| Three Months Ended | Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| Sept. 30, | Sept. 30, | Sept. 30, | June 30, | Sept. 30, | Sept. 30, | |||||||||||||||||||
| 2014 | 2013 | Change | 2014 | 2014 | Change | 2014 | 2013 | Change | ||||||||||||||||
| Rigs Utilized | 79.1 | 63.5 | 25% | 79.1 | 73.5 | 8% | 73.5 | 65.0 | 13% | |||||||||||||||
| Operating Margins (1) | 45% | 41% | 10% | 45% | 42% | 7% | 42% | 40% | 5% | |||||||||||||||
|
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1) |
$ | 53.9 | $ | 41.7 | 29% | $ | 53.9 | $ | 47.8 | 13% | $ | 144.5 | $ | 124.6 | 16% | |||||||||
|
(1) Operating profit before depreciation is calculated by taking |
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MID-STREAM SEGMENT INFORMATION
Per day liquids sold and processed volumes increased 32% and 17%,
respectively, as compared to the third quarter of 2013. For the quarter,
per day gathered volumes were 319,692 Mcf, a 2% decrease from the third
quarter of 2013. Compared to the second quarter of 2014, liquids sold
and processed volumes per day increased 1% and 5%, respectively, while
gathered volumes per day decreased 2%. Operating profit (as defined in
the footnote below) for the quarter was $13.3 million, an increase of 5%
over the third quarter of 2013 and a decrease of 5% from the second
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 | Nine Months Ended | ||||||||||||||||
| Sept. 30, | Sept. 30, | Sept. 30, | June 30, | Sept. 30, | Sept. 30, | |||||||||||||
| 2014 | 2013 | Change | 2014 | 2014 | Change | 2014 | 2013 | Change | ||||||||||
| Gas Gathering, Mcf/day | 319,692 | 326,474 | (2)% | 319,692 | 326,028 | (2)% | 316,658 | 308,645 | 3% | |||||||||
| Gas processing, Mcf/day | 169,357 | 145,020 | 17% | 169,357 | 161,509 | 5% | 160,373 | 137,725 | 16% | |||||||||
| Liquids Sold, Gallons/day | 771,334 | 586,446 | 32% | 771,334 | 762,205 | 1% | 748,805 | 505,584 | 48% | |||||||||
|
Operating Profit Before Depreciation, Depletion, & Amortization (MM) (1) |
$ 13.3 | $ 12.7 | 5% | $ 13.3 | $ 14.0 | (5)% | $ 39.5 | $ 31.8 | 24% | |||||||||
|
(1) Operating profit before depreciation is calculated by taking |
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Larry Pinkston said: “Our midstream segment continues to benefit from
prior capital investments, and as a result we have seen solid growth
throughout the year. We are nearing completion of the Buffalo Wallow
system connection to our Hemphill processing system which is anticipated
to start operation at the end of the fourth quarter. We have also
entered into a fee-based contract for our new Snowshoe project in the
Marcellus. This project will consist of the construction of a
seven-mile, 16 inch and 24 inch trunkline to gather production in Centre
County, Pennsylvania for delivery to an interstate pipeline.
Construction has started with an expected completion date in the third
quarter of 2015.”
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $676.8 million (consisting
of $646.0 million of senior subordinated notes, net of unamortized
discount, and $30.8 million of credit agreement borrowings), and a debt
to capitalization ratio of 22%. 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.
WEBCAST
Unit will webcast its third quarter earnings conference call live over
the Internet on November 4, 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
oil and natural gas segment, development, operational, implementation,
and opportunity risks, possible delays caused by limited availability of
third-party services needed in its operations, unexpected delays or
operational issues associated with the company’s new drilling rig
design, 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.
| Unit Corporation | ||||||||||||||||
|
Selected Financial and Operations Highlights |
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|
(In thousands except per share amounts) |
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| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Statement of Operations: | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Oil and natural gas | $ | 188,471 | $ | 157,320 | $ | 575,176 | $ | 475,728 | ||||||||
| Contract drilling | 120,652 | 100,647 | 341,530 | 313,180 | ||||||||||||
| Gas gathering and processing | 91,851 | 75,809 | 277,687 | 203,821 | ||||||||||||
| Total revenues | 400,974 | 333,776 | 1,194,393 | 992,729 | ||||||||||||
| Expenses: | ||||||||||||||||
| Oil and natural gas: | ||||||||||||||||
| Operating costs | 48,841 | 50,139 | 133,979 | 138,171 | ||||||||||||
|
Depreciation, depletion, and amortization |
70,033 | 56,294 | 200,958 | 163,612 | ||||||||||||
| Contract drilling: | ||||||||||||||||
| Operating costs | 66,727 | 58,988 | 197,025 | 188,580 | ||||||||||||
| Depreciation | 22,560 | 17,402 | 61,194 | 52,570 | ||||||||||||
| Gas gathering and processing: | ||||||||||||||||
| Operating costs | 78,558 | 63,098 | 238,166 | 172,065 | ||||||||||||
| Depreciation and amortization | 10,272 | 8,773 | 29,972 | 24,143 | ||||||||||||
| General and administrative | 10,172 | 9,936 | 30,409 | 28,288 | ||||||||||||
| (Gain) loss on disposition of assets | 529 | (4,345 | ) | (9,092 | ) | (7,744 | ) | |||||||||
| Total operating expenses | 307,692 | 260,285 | 882,611 | 759,685 | ||||||||||||
| Income from operations | 93,282 | 73,491 | 311,782 | 233,044 | ||||||||||||
| Other income (expense): | ||||||||||||||||
| Interest, net | (4,280 | ) | (3,625 | ) | (12,201 | ) | (11,777 | ) | ||||||||
| Gain (loss) on derivatives | 19,841 | (13,760 | ) | (9,234 | ) | (3,340 | ) | |||||||||
| Other | (68 | ) | (14 | ) | 3 | (171 | ) | |||||||||
| Total other income (expense) | 15,493 | (17,399 | ) | (21,432 | ) | (15,288 | ) | |||||||||
| Income before income taxes | 108,775 | 56,092 | 290,350 | 217,756 | ||||||||||||
| Income tax expense: | ||||||||||||||||
| Current | 5,451 | 2,111 | 23,721 | 6,745 | ||||||||||||
| Deferred | 35,802 | 19,749 | 87,802 | 77,566 | ||||||||||||
| Total income taxes | 41,253 | 21,860 | 111,523 | 84,311 | ||||||||||||
| Net income | $ | 67,522 | $ | 34,232 | $ | 178,827 | $ | 133,445 | ||||||||
| Net income per common share: | ||||||||||||||||
| Basic | $ | 1.39 | $ | 0.71 | $ | 3.68 | $ | 2.77 | ||||||||
| Diluted | $ | 1.37 | $ | 0.70 | $ | 3.65 | $ | 2.75 | ||||||||
| Weighted average shares outstanding: | ||||||||||||||||
| Basic | 48,650 | 48,254 | 48,596 | 48,193 | ||||||||||||
| Diluted | 49,177 | 48,658 | 49,054 | 48,510 | ||||||||||||
| September 30, | December 31, | |||||||
| 2014 | 2013 | |||||||
| Balance Sheet Data: | ||||||||
| Current assets | $ | 220,127 | $ | 212,031 | ||||
| Total assets | $ | 4,431,811 | $ | 4,022,390 | ||||
| Current liabilities | $ | 351,339 | $ | 243,573 | ||||
| Long-term debt | $ | 676,843 | $ | 645,696 | ||||
| Other long-term liabilities | $ | 147,214 | $ | 158,331 | ||||
| Deferred income taxes | $ | 888,915 | $ | 801,398 | ||||
| Shareholders’ equity | $ | 2,367,500 | $ | 2,173,392 | ||||
| Nine Months Ended September 30, | |||||||||
| 2014 | 2013 | ||||||||
| Statement of Cash Flows Data: | |||||||||
|
Cash flow from operations before changes in operating assets and |
$ | 565,135 | $ | 468,537 | |||||
| Net change in operating assets and liabilities | (15,608 | ) | 32,424 | ||||||
| Net cash provided by operating activities | $ | 549,527 | $ | 500,961 | |||||
| Net cash used in investing activities | $ | (636,761 | ) | $ | (422,658 | ) | |||
| Net cash provided by (used in) financing activities | $ | 69,536 | $ | (77,536 | ) | ||||
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 nine months ended September 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 |
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| Nine Months Ended | ||||||||
| September 30, | ||||||||
| 2014 | 2013 | |||||||
| (In thousands) | ||||||||
| Net cash provided by operating activities | $ | 549,527 | $ | 500,961 | ||||
| Net change in operating assets and liabilities | 15,608 | (32,424 | ) | |||||
|
Cash flow from operations before changes in operating assets and |
$ | 565,135 | $ | 468,537 | ||||
________________
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.
| Unit Corporation | |||||||||||||||||||
| Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense |
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| Three Months Ended | Nine Months Ended | ||||||||||||||||||
| June 30, | September 30, | September 30, | |||||||||||||||||
| 2014 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||
| (In thousands except operating days and operating margins) | |||||||||||||||||||
| Contract drilling revenue | $ | 114,278 | $ | 120,652 | $ | 100,647 | $ | 341,530 | $ | 313,180 | |||||||||
| Contract drilling operating cost | 66,494 | 66,727 | 58,988 | 197,025 | 188,580 | ||||||||||||||
| Operating profit from contract drilling | 47,784 | 53,925 | 41,659 | 144,505 | 124,600 | ||||||||||||||
|
Add: Elimination of intercompany rig profit and bad debt expense |
7,808 |
|
7,553 |
|
4,579 |
20,674 |
|
11,674 |
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|
Operating profit from contract drilling before elimination of |
55,592 | 61,478 | 46,238 | 165,179 | 136,274 | ||||||||||||||
| Contract drilling operating days | 6,684 | 7,276 | 5,838 | 20,073 | 17,739 | ||||||||||||||
|
Average daily operating margin before elimination of intercompany |
$ | 8,317 | $ | 8,449 | $ | 7,920 | $ | 8,229 | $ | 7,682 | |||||||||
________________
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 |
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|
Reconciliation of Adjusted Net Income and Adjusted Diluted |
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| Three Months Ended | Nine Months Ended | ||||||||||||||||
| September 30, | September 30, | ||||||||||||||||
| 2014 | 2013 | 2014 | 2013 | ||||||||||||||
|
|
(In thousands except earnings per share) |
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| Adjusted net income: | |||||||||||||||||
| Net income | $ | 67,522 | $ | 34,232 | $ | 178,827 | $ | 133,445 | |||||||||
|
(Gain) loss on derivatives not designated as hedges and hedge |
(12,163 | ) | 8,455 | 5,659 | 2,047 | ||||||||||||
|
Settlements during the period of matured derivative contracts (net |
(630 | ) | (1,493 | ) | (11,635 | ) | (965 | ) | |||||||||
| Adjusted net income | $ | 54,729 | $ | 41,194 | $ | 172,851 | $ | 134,527 | |||||||||
| Adjusted diluted earnings per share: | |||||||||||||||||
| Diluted earnings per share | $ | 1.37 | $ | 0.70 | $ | 3.65 | $ | 2.75 | |||||||||
|
Diluted earnings per share from the (gain) loss on derivatives |
(0.25 | ) | 0.18 | 0.11 | 0.04 |
|
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|
Diluted earnings per share from the settlements of matured |
(0.01 | ) | (0.03 | ) | (0.24 | ) | (0.02 | ) | |||||||||
| Adjusted diluted earnings per share | $ | 1.11 | $ | 0.85 | $ | 3.52 | $ | 2.77 | |||||||||
________________
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.
Unit Corporation
Michael D. Earl, 918-493-7700
Vice President,
Investor Relations
www.unitcorp.com
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