Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the third quarter 2016. Third quarter and
recent highlights include:
- To date, the contract drilling segment
increased the number of drilling rigs in service from a low of 13
to 20, a 54% increase. Average drilling rig utilization increased
19% quarter over quarter.
- Unit also was awarded a term contract
for its ninth BOSS drilling rig, with completion expected in
January 2017.
- After the quarter, the oil and natural
gas segment put one drilling rig back into service in the Southern
Oklahoma Hoxbar Oil Trend (SOHOT) play and is planning to put into
service a second drilling rig in the Granite Wash play later in the
fourth quarter.
- Midstream segment connected six new
wells to its Pittsburgh Mills gathering system in Butler County,
Pennsylvania, increasing the average daily throughput volume to
approximately 151 million cubic feet (MMcf) per day, a 6% increase
over the second quarter of 2016.
- Reduced long-term debt by $21 million
from the end of the second quarter, bringing the total year-to-date
reduction to $64 million.
- October redetermination of Unit's
borrowing base amount was maintained at $475 million.
THIRD QUARTER AND FIRST NINE MONTHS 2016 FINANCIAL RESULTS
Unit recorded a net loss of $24.0 million for the quarter, or
$0.48 per share, compared to a net loss of $205.3 million, or $4.18
per share, for the third quarter of 2015. For the third quarter of
2016 and 2015, Unit incurred pre-tax non-cash ceiling test
write-downs of $49.4 million and $329.9 million, respectively, in
the carrying value of its oil and natural gas properties. These
non-cash ceiling test write-downs resulted from continued lower
commodity prices. Adjusted net income (which excludes the effect of
non-cash commodity derivatives and the effect of the non-cash
write-down) for the quarter was $1.7 million, or $0.04 per share
(see Non-GAAP financial measures below). Total revenues were $153.4
million (51% oil and natural gas, 17% contract drilling, and 32%
midstream), compared to $212.4 million (45% oil and natural gas,
31% contract drilling, and 24% midstream) for the third quarter of
2015. Adjusted EBITDA for the quarter was $67.3 million, or $1.33
per diluted share (see Non-GAAP financial measures below).
For the first nine months of 2016, Unit recorded a net loss of
$137.3 million, or $2.75 per share, compared to a net loss of
$728.0 million, or $14.83 per share, for the first nine months of
2015. Unit incurred pre-tax non-cash ceiling test write-downs of
$161.6 million and $1.1 billion in the carrying value of its oil
and natural gas properties during the first nine 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 $26.0 million, or $0.52 per
share, for the first nine months of 2016 (see Non-GAAP financial
measures below). Total revenues for the first nine months were
$427.9 million (48% oil and natural gas, 21% contract drilling, and
31% midstream), compared to $681.9 million (45% oil and natural
gas, 32% contract drilling, and 23% midstream) for the first nine
months of 2015. Adjusted EBITDA for the first nine months was
$169.8 million, or $3.37 per diluted share (see Non-GAAP financial
measures below).
OIL AND NATURAL GAS SEGMENT INFORMATION
For the quarter, total production was 4.2 million barrels of oil
equivalent (MMBoe), a decrease of 17% from the third quarter of
2015 and a 4% decrease from the second quarter of 2016. The
decrease from the second quarter of 2016 was due primarily to
approximately 0.6 billion cubic feet equivalent (Bcfe) of
production in the Wilcox play being shut in for six days during the
third quarter because of maintenance on a third-party operated
processing plant. Liquids (oil and NGLs) production represented 47%
of total equivalent production. Oil production was 7,618 barrels
per day, a decrease of 26% from the third quarter of 2015 and a
decrease of 8% from the second quarter of 2016. NGLs production was
13,698 barrels per day, a decrease of 6% from the third quarter of
2015 and a 4% increase over the second quarter of 2016. Natural gas
production was 145,642 thousand cubic feet (Mcf) per day, a
decrease of 19% from the third quarter of 2015 and a decrease of 8%
from the second quarter of 2016. Total production for the first
nine months of 2016 was 13.1 MMBoe.
Unit’s average realized per barrel equivalent price was $18.29,
a decrease of 11% from the third quarter of 2015 and a 12% increase
over the second quarter of 2016. Unit’s average natural gas price
was $2.29 per Mcf, a decrease of 14% from the third quarter of 2015
and an increase of 27% over the second quarter of 2016. Unit’s
average oil price was $42.79 per barrel, a decrease of 16% from the
third quarter of 2015 and an increase of 3% over the second quarter
of 2016. Unit’s average NGLs price was $12.68 per barrel, a 45%
increase over the third quarter of 2015 and an increase of 11% over
the second quarter of 2016. All prices in this paragraph include
the effects of derivative contracts.
In the SOHOT area, Unit’s production per day for the quarter
decreased from the second quarter of 2016 in line with its
expectations, due to natural decline rates and because no new wells
were completed in the third quarter. Unit was able to increase its
leasehold in the core area of the play by 2% during the third
quarter to over 19,700 net acres. As planned, the company added a
Unit drilling rig in late October to drill two horizontal Marchand
oil wells within the SOHOT area in the fourth quarter of this year.
After drilling these two wells, the drilling rig will be released
for three to four months as performance of the two wells is
monitored before resuming drilling for the remainder of 2017.
In the Wilcox area, production for the third quarter of 2016
averaged 90 MMcfe per day, which is a 7% decrease as compared to
the second quarter of 2016. The decrease in quarter over quarter
production was a result of maintenance on a third-party operated
processing plant which caused production to be shut in for six days
during the quarter. The processing plant was back to full
operational capability by early August, and September production
averaged 100 MMcfe per day. During the third quarter, Unit
completed six new behind pipe Wilcox recompletions and three
workovers, which resulted in natural gas and oil production from
these nine wells increasing from 1,300 Mcf per day to 15,400 Mcf
per day and 140 barrels of oil per day to 850 barrels of oil per
day, respectively, from the beginning of the quarter to the end of
the quarter.
In the Texas Panhandle, Unit’s Granite Wash play operational
results for the third quarter exceeded its expectations as
production per day increased 3% as compared to the prior quarter.
The increase was due to the Dixon extended lateral well continuing
to outperform expectations as well as production increases from
several recompletions and workovers that helped offset the natural
decline of existing wells. In December, the company will add a Unit
drilling rig and initiate an extended lateral Granite Wash drilling
program in the Buffalo Wallow field. Current plans are to run this
drilling rig for all of 2017.
Larry Pinkston, Unit’s Chief Executive Officer and President,
said: “Our Wilcox vertical behind pipe recompletion activity
continues to produce strong results. In the Granite Wash, our
extended lateral Dixon well is outperforming our type curve.
Following two quarters of no new drilling activity, we recommenced
our drilling program primarily in the SOHOT and Granite Wash plays.
We are continuing our plan of maintaining a capital expenditure
level within cash flow. While it is our intention to keep at least
a two drilling rig program going for the foreseeable future, such
action will be dependent on prevailing conditions."
This table illustrates certain comparative production, realized
prices, and operating profit for the periods indicated:
Three Months Ended
Three Months Ended Nine Months Ended
Sept. 30, 2016 Sept. 30,
2015 Change Sept. 30, 2016 June
30, 2016 Change Sept. 30, 2016
Sept. 30, 2015 Change Oil and NGLs Production,
MBbl 1,961 2,289 (14 )%
1,961 1,950 1 % 6,005
6,950 (14 )% Natural Gas Production, Bcf
13.4 16.6 (19 )% 13.4
14.5 (7 )% 42.4 49.6
(15 )% Production, MBoe 4,194
5,053 (17 )% 4,194 4,359
(4 )% 13,068 15,225 (14 )% Production,
MBoe/day 45.6 54.9 (17 )%
45.6 47.9 (5 )% 47.7
55.8 (14 )% Avg. Realized Natural Gas Price, Mcf (1)
$ 2.29 $ 2.66 14 % $ 2.29 $ 1.80
27 % $ 1.98 $ 2.76 (28 )% Avg. Realized NGL
Price, Bbl (1) $ 12.68 $ 8.74 45 % $
12.68 $ 11.38 11 % $ 10.16 $ 9.83 3 %
Avg. Realized Oil Price, Bbl (1) $ 42.79 $
50.87 16 % $ 42.79 $ 41.52 3 % $ 38.71
$ 51.46 (25 )% Realized Price / Boe (1) $
18.29 $ 20.61 (11 )% $ 18.29 $ 16.27 12
% $ 16.02 $ 21.66 (26 )% Operating Profit Before
Depreciation, Depletion, & Amortization (MM) (2)
$ 52.8 $ 57.9 (9 )% $ 52.8 $
35.9 47 % $ 113.6 $ 180.1 (37 )%
(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
Oct'16 - Dec'16 Collar 3,450
$47.79 $54.52 Oct'16 - Dec'16
3-Way Collar 700 $46.50
$35.00 $57.00 Oct'16 - Dec'16 3-Way Collar (1)
700 $47.50 $35.00 $63.50
Jan'17 - Dec'17 3-Way Collar 3,750
$49.79 $39.58 $60.98
Natural Gas Period
Structure
VolumeMMBtu/Day
WeightedAverageFixed
Price
WeightedAverageFloor
Price
WeightedAverageSubfloor
Price
WeightedAverageCeiling
Price
Oct'16 - Dec'16 Swap 45,000 $2.596
Jan'17 - Mar'17
Swap 10,000 $3.550
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)
Oct'16 - Dec'16 Collar 42,000
$2.40 $2.88 Jan'17 - Oct'17
Collar 20,000 $2.88
$3.10 Oct'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 16.0, a decrease of 49% from the third quarter of 2015
and an increase of 19% over the second quarter of 2016. Per day
drilling rig rates averaged $17,479, a decrease of 7% from the
third quarter of 2015 and a 6% decrease from the second quarter of
2016. For the first nine months of 2016, per day drilling rig rates
averaged $18,147, an 8% decrease from the first nine months of
2015. Average per day operating margin for the quarter was $4,546
(with no elimination of intercompany drilling rig profit and bad
debt expense). This compares to third quarter 2015 average
operating margin of $10,368 (before elimination of intercompany
drilling rig profit and bad debt expense of $0.2 million), a
decrease of 56%, or $5,822. Third quarter 2016 average operating
margin increased 7%, or $287, as compared to that of $4,259 for the
second 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 no early termination fees from the
cancellation of certain long-term contracts, compared to early
termination fees of $11.4 million, or $3,958 per day, during the
third quarter of 2015 and $0.4 million, or $342 per day, for the
second quarter of 2016.
Pinkston said: “Commodity prices continued to increase during
the quarter, and we have seen an uptick in operator inquiries to
contract drilling rigs, resulting in an increase in our average
utilization rate over the previous quarter. After the end of the
quarter, we contracted our remaining BOSS drilling rig, bringing
all eight of our BOSS drilling rigs under contract. Additionally,
we were awarded a term contract for a ninth BOSS drilling rig with
construction expected to be completed in January 2017. Our drilling
rig fleet totals 94 drilling rigs, of which 20 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
nine of our drilling rigs. Of the nine, one is up for renewal
during the fourth quarter, seven in 2017 and one in 2018.”
This table illustrates certain comparative results for the
periods indicated:
Three Months Ended Three
Months Ended Nine Months Ended
Sept. 30,2016
Sept. 30,2015
Change
Sept. 30,2016
June 30,2016
Change
Sept. 30,2016
Sept. 30,2015
Change Rigs Utilized 16.0
31.2 (49 )% 16.0 13.5 19 %
16.7 37.3 (55 )% Operating Profit
Before Depreciation, Depletion, & Amortization (MM) (1)
$ 6.7 $ 29.5 (77 )% $ 6.7 $ 5.0
34 % $ 22.3 $ 91.4 (76 )%
(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.)
MIDSTREAM SEGMENT INFORMATION
For the quarter, per day gas gathered volumes increased 20%,
while gas processed and liquids sold volumes decreased 18% and 4%,
respectively, as compared to the third quarter of 2015. Compared to
the second quarter of 2016, liquids sold volumes per day increased
5%, while gas gathered and gas processed volumes per day decreased
2% and 6%, respectively. Operating profit (as defined in the
footnote below) for the quarter was $13.0 million, an increase of
25% over the third quarter of 2015 and an increase of 4% over the
second quarter of 2016.
For the first nine months of 2016, per day gas gathered volumes
increased 19%, while gas processed and liquids sold volumes per day
decreased 14% and 8%, respectively, as compared to the first nine
months of 2015. Operating profit (as defined in the footnote below)
for the first nine months of 2016 was $33.6 million, an increase of
6% over the first nine months of 2015.
This table illustrates certain comparative results for the
periods indicated:
Three Months Ended Three
Months Ended Nine Months Ended
Sept. 30,2016
Sept. 30,2015
Change
Sept. 30,2016
June 30,2016
Change
Sept. 30,2016
Sept. 30,2015
Change Gas Gathering, Mcf/day 429,693
357,427 20 % 429,693
439,937 (2 )% 417,722 351,619 19
% Gas Processing, Mcf/day 152,651
185,625 (18 )% 152,651 161,619
(6 )% 160,411 186,929 (14 )% Liquids
Sold, Gallons/day 558,843 579,556
(4 )% 558,843 532,215 5 %
536,911 582,760 (8 )% Operating Profit Before
Depreciation, Depletion, & Amortization (MM) (1) $ 13.0
$ 10.4 25 % $ 13.0 $ 12.5
4 % $ 33.6 $ 31.8 6 %
(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 Marcellus, additional well connections to
our Pittsburgh Mills system in Butler County, Pennsylvania have
increased average daily throughput volume to approximately 151 MMcf
per day, a 6% increase over the second quarter of 2016. Due to low
liquids prices, our midstream segment remained in 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 $854.6 million (a
reduction of $20.5 million from the end of the second quarter and
$64.4 million from the end of 2015). Long-term debt consisted of
$639.6 million of senior subordinated notes net of unamortized
discount and debt issuance costs and $215.0 million of borrowings
under its credit agreement. Recently, Unit's borrowing base was
redetermined with no change to availability. 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.
WEBCAST
Unit will webcast its third quarter earnings conference call
live over the Internet on November 3, 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 Nine Months Ended
September 30, September 30,
2016 2015 2016
2015 Statement of Operations: Revenues:
Oil and natural gas $ 78,854 $ 96,619 $ 206,318 $ 309,944 Contract
drilling 25,819 65,022 88,786 215,114 Gas gathering and processing
48,735 50,752 132,793
156,881 Total revenues 153,408
212,393 427,897 681,939
Expenses: Oil and natural gas: Operating costs 26,014 38,688 92,691
129,871 Depreciation, depletion, and amortization 27,135 57,159
89,378 202,378 Impairment of oil and natural gas properties 49,443
329,924 161,563 1,141,053 Contract drilling: Operating costs 19,137
35,486 66,489 123,717 Depreciation 11,318 14,255 34,431 42,533
Impairment of contract drilling equipment — — — 8,314 Gas gathering
and processing: Operating costs 35,738 40,314 99,185 125,081
Depreciation and amortization 11,436 10,976 34,410 32,518 General
and administrative 8,932 7,643 26,029 26,637 (Gain) loss on
disposition of assets (154 ) 7,230 (823
) 6,270 Total operating expenses 188,999
541,675 603,353 1,838,372
Loss from operations (35,591 ) (329,282
) (175,456 ) (1,156,433 ) Other income
(expense): Interest, net (10,002 ) (8,286 ) (30,225 ) (23,482 )
Gain (loss) on derivatives 6,969 8,250 (4,774 ) 12,917 Other
3 16 (11 ) 38 Total other
income (expense) (3,030 ) (20 ) (35,010 )
(10,527 ) Loss before income taxes (38,621 ) (329,302
) (210,466 ) (1,166,960 ) Income tax expense (benefit):
Current — (2,584 ) — (1,716 ) Deferred (14,599 )
(121,437 ) (73,159 ) (437,220 ) Total income taxes
(14,599 ) (124,021 ) (73,159 ) (438,936
) Net loss $ (24,022 ) $ (205,281 ) $ (137,307 ) $ (728,024
) Net loss per common share: Basic $ (0.48 ) $ (4.18 ) $
(2.75 ) $ (14.83 ) Diluted $ (0.48 ) $ (4.18 ) $ (2.75 ) $ (14.83 )
Weighted average shares outstanding: Basic 50,081 49,155
50,012 49,094 Diluted 50,081 49,155 50,012 49,094
September 30, December 31,
2016 2015
Balance Sheet Data: Current assets $ 93,646 $ 140,258 Total
assets $ 2,481,191 $ 2,799,842 Current liabilities $ 135,988 $
150,891 Long-term debt $ 854,583 $ 918,995 Other long-term
liabilities and non-current derivative liability $ 103,922 $
140,626 Deferred income taxes $ 197,122 $ 275,750 Shareholders’
equity $ 1,189,576 $ 1,313,580
Nine Months Ended
September 30, 2016
2015 Statement of Cash Flows Data: Cash flow from
operations before changes in operating assets and liabilities $
134,138 $ 303,719 Net change in operating assets and liabilities
63,624 77,763 Net cash provided by
operating activities $ 197,762 $ 381,482 Net cash
used in investing activities $ (107,509 ) $ (474,190 ) Net cash
(used in) provided by financing activities $ (90,175 ) $ 92,553
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 nine months ended September
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 Nine
Months Ended September 30, September 30,
2016 2015 2016
2015 (In thousands except earnings per share)
Adjusted net income: Net loss $ (24,022 ) $ (205,281 ) $ (137,307 )
$ (728,024 ) Impairment (net of income tax) 30,778 205,378 100,573
715,481 (Gain) loss on derivatives (net of income tax) (4,627 )
(5,272 ) 3,115 (8,058 ) Settlements during the period of matured
derivative contracts (net of income tax) (381 ) 6,837
7,656 20,060 Adjusted net income
(loss) $ 1,748 $ 1,662 $ (25,963 ) $ (541 )
Adjusted diluted earnings per share: Diluted loss per share $ (0.48
) $ (4.18 ) $ (2.75 ) $ (14.83 ) Diluted earnings per share from
impairments 0.61 4.18 2.01 14.57 Diluted earnings per share from
(gain) loss on derivatives (0.09 ) (0.11 ) 0.06 (0.16 ) Diluted
earnings (loss) per share from settlements of matured derivative
contracts — 0.14 0.16
0.41 Adjusted diluted income (loss) per share $ 0.04
$ 0.03 $ (0.52 ) $ (0.01 )
________________
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 Nine Months Ended June 30,
September 30, September 30, 2016
2016 2015 2016
2015 (In thousands) Oil and natural gas $ 35,859 $
52,840 $ 57,931 $ 113,627 $ 180,073 Contract drilling 5,003 6,682
29,536 22,297 91,397 Gas gathering and processing 12,477
12,997 10,438 33,608
31,800 Total operating profit 53,339 72,519
97,905 169,532 303,270 Depreciation, depletion and amortization
(52,844 ) (49,889 ) (82,390 ) (158,219 ) (277,429 ) Impairments
(74,291 ) (49,443 ) (329,924 ) (161,563
) (1,149,367 ) Total operating loss (73,796 ) (26,813 )
(314,409 ) (150,250 ) (1,123,526 ) General and administrative
(8,382 ) (8,932 ) (7,643 ) (26,029 ) (26,637 ) Gain (loss) on
disposition of assets 477 154 (7,230 ) 823 (6,270 ) Interest, net
(10,606 ) (10,002 ) (8,286 ) (30,225 ) (23,482 ) Gain (loss) on
derivatives (22,672 ) 6,969 8,250 (4,774 ) 12,917 Other 1
3 16 (11 ) 38
Loss before income taxes $ (114,978 ) $ (38,621 ) $ (329,302
) $ (210,466 ) $ (1,166,960 )
________________
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 Nine Months
Ended June 30, September 30,
September 30, 2016 2016
2015 2016 2015 (In thousands
except for operating days and operating margins) Contract
drilling revenue $ 24,257 $ 25,819 $ 65,022 $ 88,786 $ 215,114
Contract drilling operating cost 19,254 19,137
35,486 66,489 123,717 Operating profit from contract
drilling 5,003 6,682 29,536 22,297 91,397 Add: Elimination of
intercompany rig profit and bad debt expense 235 —
219 235 3,666 Operating profit from contract
drilling before elimination of intercompany rig profit and bad debt
expense 5,238 6,682 29,755 22,532 95,063 Contract drilling
operating days 1,230 1,470 2,870 4,578
10,175 Average daily operating margin before elimination of
intercompany rig profit and bad debt expense $ 4,259 $ 4,546 $
10,368 $ 4,922 $ 9,343
________________
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
Nine Months EndedSeptember
30,
2016 2015 (In thousands) Net
cash provided by operating activities $ 197,762 $ 381,482 Net
change in operating assets and liabilities (63,624 )
(77,763 ) Cash flow from operations before changes in operating
assets and liabilities $ 134,138 $ 303,719
________________
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 Nine Months
Ended September 30, September 30, 2016
2015 2016 2015 (In
thousands except earnings per share) Net loss $ (24,022 ) $
(205,281 ) $ (137,307 ) $ (728,024 ) Income taxes (14,599 )
(124,021 ) (73,159 ) (438,936 ) Depreciation, depletion and
amortization 50,501 83,163 160,023 279,739 Impairment 49,443
329,924 161,563 1,149,367 Interest expense 10,002 8,286 30,225
23,482 (Gain) loss on derivatives (6,969 ) (8,250 ) 4,774 (12,917 )
Settlements during the period of matured derivative contracts (457
) 11,074 11,735 32,156 Stock compensation plans 2,961 185 10,664
12,514 Other non-cash items 634 843 2,147 2,629 Gain on disposition
of assets (154 ) 7,230 (823 )
6,270 Adjusted EBITDA $ 67,340 $ 103,153 $
169,842 $ 326,280 Diluted loss per share $
(0.48 ) $ (4.18 ) $ (2.75 ) $ (14.83 ) Diluted earnings per share
from income taxes (0.29 ) (2.52 ) (1.46 ) (8.94 ) Diluted earnings
per share from depreciation, depletion and amortization 1.00 1.68
3.17 5.67 Diluted earnings per share from impairments 0.98 6.71
3.24 23.41 Diluted earnings per share from interest expense 0.20
0.17 0.60 0.48 Diluted earnings per share from (gain) loss on
derivatives (0.14 ) (0.17 ) 0.09 (0.26 ) Diluted earnings per share
from settlements during the period of matured derivative contracts
(0.01 ) 0.23 0.25 0.66 Diluted earnings per share from stock
compensation plans 0.06 — 0.21 0.25 Diluted earnings per share from
other non-cash items 0.01 0.02 0.04 0.05 Diluted earnings per share
from gain on disposition of assets — 0.15
(0.02 ) 0.13 Adjusted EBITDA per
diluted share $ 1.33 $ 2.09 $ 3.37 $ 6.62
________________
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/20161103005369/en/
Unit CorporationMichael D. Earl, 918-493-7700Vice President,
Investor Relationswww.unitcorp.com
Unit (NYSE:UNT)
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