Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the second quarter 2016. Highlights
include:
- Record production of approximately 97
million cubic feet equivalent (MMcfe) per day in its Wilcox play,
representing a 25% increase over the second quarter of 2015 and a
9% increase over the first quarter of 2016.
- Seven of its eight BOSS drilling rigs
currently operating under contract, compared to six during the
first quarter of 2016.
- Midstream segment's gas gathered and
liquids sold volumes per day increased 15% and 2%, respectively,
compared to the first quarter of 2016.
- Midstream segment connected additional
well pads to its Pittsburgh Mills gathering system in Butler
County, Pennsylvania and its new Snow Shoe gathering system in
Centre County, Pennsylvania.
SECOND QUARTER AND FIRST SIX MONTHS 2016 FINANCIAL RESULTS
Unit recorded a net loss of $72.1 million for the quarter, or
$1.44 per share, compared to a net loss of $274.4 million, or $5.58
per share, for the second quarter of 2015. For the second quarter
of 2016 and 2015, Unit incurred pre-tax non-cash ceiling test
write-downs of $74.3 million and $410.5 million, respectively, in
the carrying value of its oil and natural gas properties. These
non-cash ceiling test write-downs have resulted from continued
lower commodity prices. Adjusted net loss (which excludes the
effect of non-cash commodity derivatives and the effect of the
non-cash write-down) for the quarter was $7.4 million, or $0.15 per
share (see Non-GAAP financial measures below). Total revenues were
$138.3 million (50% oil and natural gas, 18% contract drilling, and
32% mid-stream), compared to $214.4 million (50% oil and natural
gas, 26% contract drilling, and 24% mid-stream) for the second
quarter of 2015. Adjusted EBITDA was $54.1 million, or $1.07 per
diluted share (see Non-GAAP financial measures below).
For the first six months of 2016, Unit recorded a net loss of
$113.3 million, or $2.27 per share, compared to a net loss of
$522.7 million, or $10.66 per share, for the first six months of
2015. Unit incurred pre-tax non-cash ceiling test write-downs of
$112.1 million and $811.1 million in the carrying value of its oil
and natural gas properties during the first six months of 2016 and
2015, respectively. Unit recorded an adjusted net loss (which
excludes the effect of non-cash commodity derivatives and the
effect of the non-cash write-down) of $27.7 million, or $0.55 per
share (see Non-GAAP financial measures below). Total revenues for
the first six months were $274.5 million (46% oil and natural gas,
23% contract drilling, and 31% mid-stream), compared to $469.5
million (45% oil and natural gas, 32% contract drilling, and 23%
mid-stream) for the first six months of 2015. Adjusted EBITDA for
the first six months was $102.5 million, or $2.04 per diluted share
(see Non-GAAP financial measures below).
OIL AND NATURAL GAS SEGMENT INFORMATION
For the quarter, total production was 4.4 million barrels of oil
equivalent (MMBoe), a decrease of 14% from the second quarter of
2015 and a 3% decrease from the first quarter of 2016. The decrease
in production resulted primarily from Unit's previous decision to
reduce its new well drilling plans because of low commodity prices.
Liquids (oil and NGLs) production represented 45% of total
equivalent production. Oil production was 8,309 barrels per day, a
decrease of 20% from the second quarter of 2015 and a decrease of
6% from the first quarter of 2016. NGLs production was 13,120
barrels per day, a decrease of 10% from the second quarter of 2015
and an 8% decrease from the first quarter of 2016. Natural gas
production was 158,844 thousand cubic feet (Mcf) per day, a
decrease of 13% from the second quarter of 2015 and essentially
flat with the first quarter of 2016. Total production for the first
six months of 2016 was 8.9 MMBoe.
Unit’s average realized per barrel equivalent price was $16.27,
a decrease of 27% from the second quarter of 2015 and a 19%
increase over the first quarter of 2016. Unit’s average natural gas
price was $1.80 per Mcf, a decrease of 33% from the second quarter
of 2015 and a decrease of 4% from the first quarter of 2016. Unit’s
average oil price was $41.52 per barrel, a decrease of 25% from the
second quarter of 2015 and an increase of 28% over the first
quarter of 2016. Unit’s average NGLs price was $11.38 per barrel, a
6% decrease from the second quarter of 2015 and an increase of 73%
over the first quarter of 2016. All prices in this paragraph
include the effects of derivative contracts.
For the quarter, Unit achieved record production of
approximately 97 MMcfe per day from its Wilcox play, representing a
25% increase over the second quarter of 2015 and a 9% increase over
the first quarter of 2016. This production growth is attributed to
first oil and natural gas sales from new horizontal wells and
behind pipe recompletions that occurred primarily in the first
quarter of 2016. Through the end of the second quarter, the company
completed new behind pipe Wilcox intervals in four existing wells
that are producing 17 MMcfe per day. These same four wells were
producing approximately 700 Mcfe per day before the recompletions.
Unit anticipates recompleting approximately four to six new behind
pipe zones during the second half of the year.
In the Southern Oklahoma Hoxbar Oil Trend (SOHOT), Unit
completed one new well during the quarter with an average 30 day IP
rate of approximately 720 barrels of oil equivalent (Boe) per day.
Unit anticipates resuming drilling Marchand oil wells during the
fourth quarter, using a Unit drilling rig.
In the Buffalo Wallow field in the Granite Wash play, a
horizontal “C1” well was completed with an extended lateral of
approximately 7,500 feet. The well, which is Unit's first extended
lateral drilled in this field, is currently producing approximately
12.1 MMcfe per day consisting of 43% natural gas, 15% oil, and 42%
NGLs. Unit anticipates beginning a one or two drilling rig extended
lateral development program in the Buffalo Wallow field late in the
fourth quarter of 2016 or early 2017.
Larry Pinkston, Unit’s Chief Executive Officer and President,
said: “We are pleased with the results of the wells that were
completed during the first half of the year as well as the results
of our behind pipe recompletions. We continue to increase our
leasehold in our core areas and identify additional potential
drilling locations. Depending on commodity prices, our plan will be
to resume our drilling program in the latter part of the year.”
This table illustrates certain comparative production, realized
prices, and operating profit for the periods indicated:
Three Months Ended
Three Months Ended Six Months
Ended
June 30,2016
June 30,2015
Change
June 30,2016
Mar. 31,2016
Change
June 30,2016
June 30,2015
Change Oil and NGLs Production, MBbl
1,950 2,277 (14 )%
1,950 2,094 (7 )%
4,044 4,661 (13 )% Natural Gas
Production, Bcf 14.5 16.7
(13 )% 14.5 14.5
— % 29.0 33.1 (12
)% Production, MBoe 4,359
5,054 (14 )% 4,359 4,514
(3 )% 8,873 10,171
(13 )% Production, MBoe/day 47.9
55.5 (14 )% 47.9
49.6 (3 )% 48.8
56.2 (13 )% Avg. Realized Natural Gas Price, Mcf (1)
$ 1.80 $ 2.67 (33 )% $
1.80 $ 1.87 (4 )% $ 1.83
$ 2.80 (35 )% Avg. Realized NGL Price, Bbl (1)
$ 11.38 $ 12.05 (6 )% $ 11.38
$ 6.59 73 % $ 8.90 $
10.37 (14 )% Avg. Realized Oil Price, Bbl (1)
$ 41.52 $ 55.52 (25 )% $ 41.52
$ 32.50 28 % $ 36.88 $
51.73 (29 )% Realized Price / Boe (1) $
16.27 $ 22.38 (27 )% $ 16.27
$ 13.67 19 % $ 14.95 $ 22.18
(33 )% Operating Profit Before Depreciation,
Depletion, & Amortization (MM) (2) $ 35.9
$ 61.3 (42 )% $ 35.9
$ 24.9 44 % $ 60.8
$ 122.1 (50 )%
(1) Realized price includes oil, natural gas
liquids, natural gas, and associated derivatives. (2) Operating
profit before depreciation is calculated by taking operating
revenues for this segment less operating expenses excluding
depreciation, depletion, amortization, and impairment. (See
non-GAAP financial measures below.)
This table summarizes the outstanding derivative contracts.
Crude Period
Structure
VolumeBbl/Day
WeightedAverageFixed
Price
WeightedAverageFloor
Price
WeightedAverageSubfloor
Price
WeightedAverageCeiling
Price
Jul'16 - Sep'16 Swap 1,000
$48.45
Jul'16 - Sep'16 Collar
2,450 $44.44
$52.46 Oct'16 - Dec'16 Collar
1,450 $47.50
$56.40 Jul'16 - Dec'16
3-Way Collar 700
$46.50 $35.00 $57.00 Jul'16 -
Dec'16 3-Way Collar (1) 700
$47.50 $35.00
$63.50 Jan'17 - Dec'17 3-Way Collar
750 $50.00
$37.50 $63.90
Natural Gas Period Structure
VolumeMMBtu/Day
WeightedAverageFixed
Price
WeightedAverageFloor
Price
WeightedAverageSubfloor
Price
WeightedAverageCeiling
Price
Jul'16 - Dec'16 Swap 45,000
$2.596
Jan'17 - Dec'17 Swap
60,000 $2.960
Jan'18 - Dec'18 Swap
10,000 $3.025
Jan'17 - Dec'17
Basis Swap 20,000 $(0.215)
Jan'18 - Dec'18 Basis Swap 10,000
$(0.208)
Jul'16 - Dec'16 Collar
42,000 $2.40
$2.88 Jan-17 - Oct'17
Collar 20,000
$2.88 $3.10 Jul'16 - Dec'16
3-Way Collar 13,500
$2.70 $2.20 $3.26
Jan'17 - Dec'17 3-Way Collar 15,000
$2.50 $2.00
$3.32
(1) Unit pays its counterparty a
premium, which can be and is being deferred until settlement.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of Unit's drilling rigs working during the
quarter was 13.5, a decrease of 56% from the second quarter of 2015
and a decrease of 34% from the first quarter of 2016. Per day
drilling rig rates averaged $18,585, a decrease of 7% from the
second quarter of 2015 and a 1% increase over the first quarter of
2016. For the first six months of 2016, per day drilling rig rates
averaged $18,468, an 8% decrease from the first six months of 2015.
Average per day operating margin for the quarter was $4,259 (before
elimination of intercompany drilling rig profit and bad debt
expense of $0.2 million). This compares to second quarter 2015
average operating margin of $6,821 (before elimination of
intercompany drilling rig profit and bad debt expense of $0.5
million), a decrease of 38%, or $2,562. Second quarter 2016 average
operating margin decreased 25%, or $1,392, as compared to that of
$5,651 for the first quarter of 2016 (in each case regarding
eliminating intercompany drilling rig profit and bad debt expense -
see Non-GAAP financial measures below). Average operating margins
for the quarter included early termination fees of approximately
$0.4 million, or $342 per day, from the cancellation of certain
long-term contracts, compared to early termination fees of $1.6
million, or $594 per day, during the second quarter of 2015 and
$2.6 million, or $1,410 per day, for the first quarter of 2016.
Pinkston said: “Although we saw a slight increase in commodity
prices during the quarter, operators remain cautious about
contracting new drilling rigs, resulting in our average utilization
rate continuing to fall quarter over quarter. Currently, we have
seven of our eight BOSS drilling rigs under contract. Our drilling
rig fleet totals 94 drilling rigs, of which 16 are working under
contract after rebounding from a low of 13 drilling rigs during the
second quarter. Long-term contracts (contracts with original terms
ranging from six months to two years in length) are in place for
five of our drilling rigs. Of the five, one is up for renewal
during the fourth quarter, and four in 2017.”
This table illustrates certain comparative results for the
periods indicated:
Three Months Ended
Three Months Ended Six Months
Ended
June 30,2016
June 30,2015
Change
June 30,2016
Mar. 31,2016
Change
June 30,2016
June 30,2015
Change Rigs Utilized 13.5
30.7 (56 )% 13.5
20.6 (34 )% 17.1
40.4 (58 )% Operating Profit Before
Depreciation, Depletion, & Amortization (MM) (1)
$ 5.0 $ 18.5 (73 )%
$ 5.0 $ 10.6 (53 )%
$ 15.6 $ 61.9 (75 )%
(1) Operating profit
before depreciation is calculated by taking operating revenues for
this segment less operating expenses excluding depreciation and
impairment. (See non-GAAP financial measures below.)
MID-STREAM SEGMENT INFORMATION
For the quarter, per day gas gathered volumes increased 21%,
while gas processed and liquids sold volumes decreased 13% and 11%,
respectively, as compared to the second quarter of 2015. Compared
to the first quarter of 2016, gas gathered and liquids sold volumes
per day increased 15% and 2%, respectively, while gas processed
volumes per day decreased 3%. Operating profit (as defined in the
footnote below) for the quarter was $12.5 million, an increase of
8% over the second quarter of 2015 and an increase of 53% over the
first quarter of 2016.
For the first six months of 2016, per day gas gathered volumes
increased 18%, while gas processed and liquids sold volumes per day
decreased 12% and 10%, respectively, as compared to the first six
months of 2015. Operating profit (as defined in the footnote below)
for the first six months of 2016 was $20.6 million, a decrease of
4% from the first six months of 2015.
This table illustrates certain comparative results for the
periods indicated:
Three Months Ended
Three Months Ended Six Months
Ended
June 30,2016
June 30,2015
Change
June 30,2016
Mar. 31,2016
Change
June 30,2016
June 30,2015
Change Gas Gathering, Mcf/day
439,937 362,896 21 %
439,937 383,405 15 %
411,671 348,666 18 % Gas
Processing, Mcf/day 161,619
186,041 (13 )% 161,619
167,048 (3 )% 164,333
187,592 (12 )% Liquids Sold, Gallons/day
532,215 599,732
(11 )% 532,215 519,433
2 % 525,824 584,389
(10 )% Operating Profit Before Depreciation, Depletion,
& Amortization (MM) (1) $ 12.5 $
11.6 8 % $ 12.5 $
8.1 53 % $ 20.6 $
21.4 (4 )%
(1)
Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses
excluding depreciation, amortization, and impairment. (See non-GAAP
financial measures below.)
Pinkston said: “In the Wilcox in southeast Texas, our Segno
system connected three new wells since the beginning of 2016. The
Segno system's average daily gathered volume increased nearly 7%
quarter over quarter to more than 90 MMcf per day. In the
Marcellus, we connected an additional well pad during the quarter
which included two new wells to our Pittsburgh Mills system in
Butler County, Pennsylvania. This connection increased average
daily gathered volume to 142 MMcf per day, a 54% increase over the
first quarter of 2016. We connected a new well pad with three wells
to our new Snow Shoe system in Centre County, Pennsylvania.
Gathered volumes for this facility continue to increase, averaging
14 MMcf per day in the second quarter. Due to low liquids prices,
our midstream segment remained in full ethane rejection mode for
most of the quarter at our various gas processing facilities in the
Mid-Continent.”
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $875.1 million (a
reduction of $23.6 million from the end of the first quarter),
consisting of $639.1 million of senior subordinated notes net of
unamortized discount and debt issuance costs and $236.0 million of
borrowings under its credit agreement. Under the credit agreement,
the amount Unit can borrow is the lesser of the amount it elects as
the commitment amount ($475 million) or the value of its borrowing
base as determined by the lenders ($475 million), but in either
event not to exceed $875 million. The credit agreement was amended
during the quarter to provide, in part, for a borrowing base of
$475 million.
WEBCAST
Unit will webcast its second quarter earnings conference call
live over the Internet on August 4, 2016 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, believes, 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 changes in commodity prices, the
productive capabilities of the Company’s wells, future demand for
oil and natural gas, future drilling rig utilization and dayrates,
projected rate of the Company’s oil and natural gas production, the
amount available to the Company for borrowings, its anticipated
borrowing needs under its credit agreement, the number of wells to
be drilled by the Company’s oil and natural gas segment, 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 Highlights
(In thousands except per share
amounts)
Three Months Ended Six Months Ended June
30, June 30, 2016
2015 2016 2015
Statement of Operations: Revenues: Oil and natural gas $
69,190 $ 107,256 $ 127,464 $ 213,325 Contract drilling 24,257
55,015 62,967 150,092 Gas gathering and processing 44,858
52,176 84,058 106,129
Total revenues 138,305 214,447
274,489 469,546 Expenses: Oil and
natural gas: Operating costs 33,331 45,972 66,677 91,183
Depreciation, depletion, and amortization 30,411 68,101 62,243
145,219 Impairment of oil and natural gas properties 74,291 410,536
112,120 811,129 Contract drilling: Operating costs 19,254 36,485
47,352 88,231 Depreciation 10,918 13,265 23,113 28,278 Impairment
of contract drilling equipment — 8,314 — 8,314 Gas gathering and
processing: Operating costs 32,381 40,592 63,447 84,767
Depreciation and amortization 11,515 10,848 22,974 21,542 General
and administrative 8,382 9,624 17,097 18,994 Gain on disposition of
assets (477 ) (415 ) (669 ) (960 )
Total operating expenses 220,006 643,322
414,354 1,296,697 Loss
from operations (81,701 ) (428,875 ) (139,865
) (827,151 ) Other income (expense): Interest, net
(10,606 ) (7,956 ) (20,223 ) (15,196 ) Gain (loss) on derivatives
(22,672 ) (1,919 ) (11,743 ) 4,667 Other 1 24
(14 ) 22 Total other income (expense)
(33,277 ) (9,851 ) (31,980 ) (10,507 )
Loss before income taxes (114,978 ) (438,726 ) (171,845 )
(837,658 ) Income tax expense (benefit): Current — 803 — 868
Deferred (42,842 ) (165,140 ) (58,560 )
(315,783 ) Total income taxes (42,842 ) (164,337 )
(58,560 ) (314,915 ) Net loss $ (72,136 ) $
(274,389 ) $ (113,285 ) $ (522,743 ) Net loss per common
share: Basic $ (1.44 ) $ (5.58 ) $ (2.27 ) $ (10.66 ) Diluted $
(1.44 ) $ (5.58 ) $ (2.27 ) $ (10.66 ) Weighted average
shares outstanding: Basic 50,074 49,148 49,977 49,063 Diluted
50,074 49,148 49,977 49,063
June 30, December 31,
2016 2015 Balance Sheet Data:
Current assets $ 89,294 $ 140,258 Total assets $ 2,552,096 $
2,799,842 Current liabilities $ 146,757 $ 150,891 Long-term debt $
875,051 $ 918,995 Other long-term liabilities $ 103,926 $ 140,341
Deferred income taxes $ 211,721 $ 275,750 Shareholders’ equity $
1,211,221 $ 1,313,580
Six Months Ended June
30, 2016 2015
Statement of Cash Flows Data: Cash flow from operations
before changes in operating assets and liabilities $ 77,734 $
207,221 Net change in operating assets and liabilities
54,982 50,385 Net cash provided by operating
activities $ 132,716 $ 257,606 Net cash used in
investing activities $ (77,386 ) $ (366,442 ) Net cash (used in)
provided by financing activities $ (55,191 ) $ 108,626
Non-GAAP Financial Measures
Unit Corporation reports its financial results in accordance
with generally accepted accounting principles (“GAAP”). The Company
believes certain non-GAAP measures provide users of its financial
information and its management additional meaningful information to
evaluate the performance of the company.
This press release includes net income (loss) and earnings
(loss) per share excluding impairment adjustments and the effect of
the cash settled commodity derivatives, its reconciliation of
segment operating profit, its drilling segment’s average daily
operating margin before elimination of intercompany drilling rig
profit and bad debt expense, its cash flow from operations before
changes in operating assets and liabilities, and its reconciliation
of net income (loss) to adjusted EBITDA.
Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three and six months ended June 30, 2016
and 2015. Non-GAAP financial measures should not be considered by
themselves or a substitute for results reported in accordance with
GAAP. This non-GAAP information should be considered by the reader
in addition to, but not instead of, the financial statements
prepared in accordance with GAAP. The non-GAAP financial
information presented may be determined or calculated differently
by other companies and may not be comparable to similarly titled
measures.
Unit Corporation
Reconciliation of Adjusted Net Income and Adjusted Diluted
Earnings per Share Three Months Ended Six
Months Ended June 30, June 30, 2016
2015 2016 2015 (In
thousands except earnings per share) Adjusted net income: Net
loss $ (72,136 ) $ (274,389 ) $ (113,285 ) $ (522,743 ) Impairment
(net of income tax) 46,246 260,734 69,795 510,103 (Gain) loss on
derivatives not designated as hedges (net of income tax) 15,650
1,238 7,742 (2,786 ) Settlements during the period of matured
derivative contracts (net of income tax) 2,870
6,495 8,037 13,223 Adjusted net
loss $ (7,370 ) $ (5,922 ) $ (27,711 ) $ (2,203 ) Adjusted
diluted earnings per share: Diluted loss per share $ (1.44 ) $
(5.58 ) $ (2.27 ) $ (10.66 ) Diluted earnings per share from
impairments 0.92 5.31 1.40 10.40 Diluted earnings per share from
(gain) loss on derivatives 0.31 0.02 0.16 (0.06 ) Diluted earnings
(loss) per share from settlements of matured derivative contracts
0.06 0.13 0.16
0.27 Adjusted diluted loss per share $ (0.15 ) $ (0.12 ) $
(0.55 ) $ (0.05 )
________________
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
analysts.
Unit Corporation
Reconciliation of Segment Operating Profit Three
Months Ended Six Months Ended March 31,
June 30, June 30, 2016 2016
2015 2016 2015
(In thousands) Oil and natural gas $ 24,928 $ 35,859 $
61,284 $ 60,787 $ 122,142 Contract drilling 10,612 5,003 18,530
15,615 61,861 Gas gathering and processing 8,134
12,477 11,584 20,611
21,362 Total operating profit 43,674 53,339 91,398 97,013
205,365 Depreciation, depletion and amortization (55,486 ) (52,844)
(92,214 ) (108,330 ) (195,039 ) Impairments (37,829 )
(74,291) (418,850 ) (112,120 ) (819,443 )
Total operating loss (49,641 ) (73,796) (419,666 ) (123,437 )
(809,117 ) General and administrative (8,715 ) (8,382) (9,624 )
(17,097 ) (18,994 ) Gain on disposition of assets 192 477 415 669
960 Interest, net (9,617 ) (10,606) (7,956 ) (20,223 ) (15,196 )
Gain (loss) on derivatives 10,929 (22,672) (1,919 ) (11,743 ) 4,667
Other (15 ) 1 24 (14 ) 22
Loss before income taxes $ (56,867 ) $ (114,978) $ (438,726
) $ (171,845 ) $ (837,658 )
________________
The Company has included segment operating profit because:
- It considers segment operating profit
to be an important supplemental measure of operating performance
for presenting trends in its core businesses.
- Segment operating profit is useful to
investors because it provides a means to evaluate the operating
performance of the segments and Company on an ongoing basis using
criteria that is used by management.
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, 2016
2016 2015 2016
2015 (In thousands except for operating days and
operating margins) Contract drilling revenue $ 38,710 $ 24,257
$ 55,015 $ 62,967 $ 150,092 Contract drilling operating cost
28,098 19,254 36,485 47,352 88,231
Operating profit from contract drilling 10,612 5,003 18,530 15,615
61,861 Add: Elimination of intercompany rig profit and bad debt
expense — 235 537 235 3,447
Operating profit from contract drilling before elimination of
intercompany rig profit and bad debt expense 10,612 5,238 19,067
15,850 65,308 Contract drilling operating days 1,878
1,230 2,795 3,108 7,305 Average daily
operating margin before elimination of intercompany rig profit and
bad debt expense $ 5,651 $ 4,259 $ 6,821 $ 5,100 $ 8,940
________________
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
Cash Flow From Operations Before Changes in Operating Assets and
Liabilities
Six Months EndedJune 30,
2016 2015 (In thousands) Net
cash provided by operating activities $ 132,716 $ 257,606 Net
change in operating assets and liabilities (54,982 )
(50,385 ) Cash flow from operations before changes in operating
assets and liabilities $ 77,734 $ 207,221
________________
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 Adjusted EBITDA and Adjusted EBITDA per
Diluted Share Three Months Ended Six Months
Ended June 30, June 30, 2016
2015 2016 2015 (In thousands
except earnings per share) Net loss $ (72,136 ) $ (274,389 )
$ (113,285 ) $ (522,743 ) Income taxes (42,842 ) (164,337 ) (58,560
) (314,915 ) Depreciation, depletion and amortization 53,406 92,986
109,522 196,576 Impairment 74,291 418,850 112,120 819,443 Interest
expense 10,606 7,956 20,223 15,196 (Gain) loss on derivatives
22,672 1,919 11,743 (4,667 ) Settlements during the period of
matured derivative contracts 5,052 10,070 12,192 21,082 Stock
compensation plans 2,905 6,466 7,703 12,329 Other non-cash items
634 825 1,513 1,786 Gain on disposition of assets (477 )
(415 ) (669 ) (960 ) Adjusted EBITDA $ 54,111
$ 99,931 $ 102,502 $ 223,127
Diluted loss per share $ (1.44 ) $ (5.58 ) $ (2.27 ) $ (10.66 )
Diluted earnings per share from income taxes (0.86 ) (3.34 ) (1.17
) (6.42 ) Diluted earnings per share from depreciation, depletion
and amortization 1.06 1.88 2.18 3.99 Diluted earnings per share
from impairments 1.49 8.52 2.25 16.71 Diluted earnings per share
from interest expense 0.21 0.16 0.40 0.31 Diluted earnings per
share from (gain) loss on derivatives 0.45 0.04 0.23 (0.09 )
Diluted earnings per share from settlements during the period of
matured derivative contracts 0.10 0.20 0.25 0.42 Diluted earnings
per share from stock compensation plans 0.06 0.13 0.15 0.25 Diluted
earnings per share from other non-cash items 0.01 0.02 0.03 0.04
Diluted earnings per share from gain on disposition of assets
(0.01 ) (0.01 ) (0.01 ) (0.02 )
Adjusted EBITDA per diluted share $ 1.07 $ 2.02 $
2.04 $ 4.53
________________
The Company has included the adjusted EBITDA excluding gain or
loss on disposition of assets and including only the cash settled
commodity derivatives because:
- It uses the adjusted EBITDA to evaluate
the operational performance of the Company.
- The adjusted EBITDA is more comparable
to estimates provided by securities analysts.
- It provides a means to assess the
ability of the Company to generate cash sufficient to pay interest
on its indebtedness.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20160804005325/en/
Unit CorporationMichael D. Earl, 918-493-7700Vice President,
Investor Relationswww.unitcorp.com
Unit (NYSE:UNT)
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