Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the second quarter 2017. Results and recent
highlights include:
- Net income of $9.1 million.
- Oil and natural gas segment production
increased 2% over the first quarter of 2017 despite service company
frac date delays and third party gathering and processing outages
adversely impacting production by 94.0 MBoe.
- Completed the Hoxbar acquisition.
- Potential for over 1,000 drilling
locations in the STACK and STACK extension plays.
- Construction was completed on the tenth
BOSS drilling rig, and it was placed into service late in the
quarter.
- Thirty-six drilling rigs are currently
operating; all ten BOSS drilling rigs are under contract.
- Midstream segment increased gathered
and processed volumes at its Hemphill and Cashion systems resulting
in a liquids sold volume increase of 7% over the first quarter of
2017.
SECOND QUARTER AND FIRST SIX MONTHS 2017 FINANCIAL RESULTS
Unit recorded net income of $9.1 million for the quarter, or
$0.17 per diluted share, compared to a net loss of $72.1 million,
or $1.44 per share, for the second quarter of 2016. Adjusted net
income (which excludes the effect of non-cash commodity
derivatives) for the quarter was $3.6 million, or $0.07 per diluted
share (see Non-GAAP financial measures below). Total revenues were
$170.6 million (49% oil and natural gas, 23% contract drilling, and
28% midstream), compared to $138.3 million (50% oil and natural
gas, 18% contract drilling, and 32% midstream) for the second
quarter of 2016. Adjusted EBITDA was $71.0 million, or $1.37 per
diluted share (see Non-GAAP financial measures below).
For the first six months of 2017, Unit recorded net income of
$25.0 million, or $0.49 per diluted share, compared to a net loss
of $113.3 million, or $2.27 per share, for the first six months of
2016. Unit recorded adjusted net income (which excludes the effect
of non-cash commodity derivatives) of $11.1 million, or $0.22 per
diluted share (see Non-GAAP financial measures below). Total
revenues for the first six months were $346.3 million (49% oil and
natural gas, 22% contract drilling, and 29% midstream), compared to
$274.5 million (46% oil and natural gas, 23% contract drilling, and
31% midstream) for the first six months of 2016. Adjusted EBITDA
for the first six months was $145.5 million, or $2.83 per diluted
share (see Non-GAAP financial measures below).
OIL AND NATURAL GAS SEGMENT INFORMATION
For the quarter, total production was 3.9 million barrels of oil
equivalent (MMBoe), a 2% increase over the first quarter of 2017.
Liquids (oil and NGLs) production represented 48% of total
equivalent production. Oil production was 7,851 barrels per day, an
increase of 10% over the first quarter of 2017. NGLs production was
12,486 barrels per day, a 2% increase over the first quarter of
2017. Natural gas production was 131,940 thousand cubic feet (Mcf)
per day, a 3% decrease from the first quarter of 2017. Total
production for the first six months of 2017 was 7.6 MMBoe. Total
production for the quarter was adversely impacted by approximately
94.0 thousand barrels of oil equivalent (MBoe) due to third party
gas processing outages and the delay of several frac jobs during
the quarter.
Unit’s average realized per barrel equivalent price was $20.76,
a 6% decrease from the first quarter of 2017. Unit’s average
natural gas price was $2.45 per Mcf, a decrease of 9% from the
first quarter of 2017. Unit’s average oil price was $46.96 per
barrel, a decrease of 4% from the first quarter of 2017. Unit’s
average NGLs price was $14.91 per barrel, a decrease of 16% from
the first quarter of 2017. All prices in this paragraph include the
effects of derivative contracts.
In the Wilcox area, the Trinity #1 exploration well in the
Cherry Creek prospect was tested during the quarter with
encouraging results. Unit is in the process of securing right of
way for pipeline installation to bring production online. It is
anticipated the pipeline will be in place early in the fourth
quarter. Recompletion and workover activities have been ongoing,
although suffering scheduling delays by the fracture stimulation
company. Unit’s strategy for the Wilcox area is to build a
horizontal well inventory and to continue exploration activities
with the goal of identifying additional Gilly-like structures. Unit
has recently added an operated rig to the area.
In the Granite Wash, Unit continues its Buffalo Wallow extended
lateral drilling program and plans to do so throughout 2017. During
the quarter, two additional wells had first production, one each in
the A-2 and C-1 intervals. Two additional wells have been drilled
in the C-1 interval and were recently completed. Production rates
from the 7,500’ extended lateral well program to date are meeting
expectations and, at a projected well cost of $6.3 million, have a
high rate of return, especially when including the margin realized
by Unit’s midstream segment that gathers and processes all gas
produced from the Buffalo Wallow field. During the quarter, we
added 200 net operated acres contiguous to the Buffalo Wallow
field, increasing Unit’s acreage position to approximately 9,000
net acres. Unit is continuing to evaluate additional opportunities
to add acreage surrounding its Buffalo Wallow field.
In the Southern Oklahoma Hoxbar Oil Trend (SOHOT) area, Unit
completed the acquisition of approximately 8,300 net acres
increasing its working interest and providing operatorship in many
sections. Unit continued its drilling program with a rig added in
late April. The Oklahoma state legislature passed a bill signed
into law in June that allows extended lateral drilling across the
state beginning in late August. Unit has begun reworking rig
schedules to incorporate longer lateral horizontal wells. It is
anticipated that longer laterals should result in further
improvement in well economics.
The STACK play has continued to expand as industry drilling
activity has further delineated its size. Unit's legacy acreage
position is now within the core of the STACK and STACK extension
areas. Unit’s acreage position totals approximately 15,000 net
acres. Unit estimates it has 90 to 130 operated drilling locations
in inventory and 450 to 650 non-operated locations in inventory in
its 10,000 net acre core STACK area. In its STACK extension area,
Unit has in excess of 5,000 net acres and estimates it has 20 to 50
operated drilling locations in inventory and 100 to 200
non-operated locations in inventory. After the land and regulatory
work is complete, Unit anticipates that its drilling program in
this area could be implemented by late 2017 or early 2018.
Larry Pinkston, Unit’s Chief Executive Officer and President,
said: “Production results for the quarter reflect the beginning of
a return to growth. While delays and unplanned outages have slowed
our progress, we now see an improving trend. We are pleased to
finally be in the position to discuss our legacy STACK acreage
position. As we have previously discussed, we have waited for third
party operator drilling activities to advance toward our position.
Now, nearby well results have helped substantiate the value of this
previously unrecognized asset. Our efforts in our other core areas
and the STACK acreage continue to add to our prospective well
inventory."
This table illustrates certain comparative production, realized
prices, and operating profit for the periods indicated:
Three Months Ended
Three Months Ended Six Months Ended
Jun 30, Jun 30,
Jun 30, Mar 31,
Jun 30, Jun 30,
2017 2016
Change
2017 2017 Change
2017 2016 Change
Oil and NGLs Production, MBbl 1,851
1,950 (5 )% 1,851
1,740 6 % 3,590 4,044
(11 )% Natural Gas Production, Bcf 12.0
14.5 (17 )% 12.0
12.2 (2 )% 24.2
29.0 (16 )% Production, MBoe 3,852
4,359 (12 )% 3,852
3,777 2 % 7,629
8,873 (14 )% Production, MBoe/day 42.3
47.9 (12 )% 42.3
42.0 1 % 42.1 48.8
(14 )% Avg. Realized Natural Gas Price, Mcf (1)
$ 2.45 $ 1.80 36 % $ 2.45
$ 2.68 (9 )% $ 2.57 $ 1.83 40 %
Avg. Realized NGL Price, Bbl (1) $ 14.91 $
11.38 31 % $ 14.91 $ 17.81 (16
)% $ 16.34 $ 8.90 84 % Avg. Realized
Oil Price, Bbl (1) $ 46.96 $ 41.52 13 %
$ 46.96 $ 48.68 (4 )% $
47.77 $ 36.88 30 % Realized Price / Boe (1)
$ 20.76 $ 16.27 28 % $ 20.76
$ 22.13 (6 )% $ 21.44 $ 14.95
43 % Operating Profit Before Depreciation, Depletion, &
Amortization (MM) (2) $ 50.4 $ 35.9 41
% $ 50.4 $ 58.4 (14 )% $
108.8 $ 60.8 79 % (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.)
CONTRACT DRILLING SEGMENT INFORMATION
The average number of Unit's drilling rigs working during the
quarter was 28.8, an increase of 13% over the first quarter of
2017. Per day drilling rig rates averaged $15,962, a 1% increase
over the first quarter of 2017. For the first six months of 2017,
per day drilling rig rates averaged $15,905, a 14% decrease from
the first six months of 2016. Average dayrates decreased primarily
because of the full effect of the repricing of three BOSS rig term
contracts, one in the mid-fourth quarter, one early first quarter,
and one during the second quarter. Unit reactivated eight stacked
SCR rigs during the first quarter and three during the second
quarter but at rates below the average dayrate for the rigs then
working. Preparing the rigs to return to service carries additional
startup and mobilization costs. These factors contributed to the
decreased average daily operating margins during the first six
months. Average per day operating margin for the quarter was $4,721
(before elimination of intercompany drilling rig profit and bad
debt expense of $0.4 million). This compares to first quarter 2017
average operating margin of $3,474 (with no elimination of
intercompany drilling rig profit and bad debt expense), an increase
of 36%, or $1,247 (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 $0.8 million, or $316 per
day, compared to no early termination fees for the first quarter of
2017.
Pinkston said: “Contract drilling industry momentum continued to
be positive throughout the quarter despite highly volatile
commodity prices. Our rig utilization continued to climb to a total
of 33 drilling rigs operating at the end of the quarter. We have 95
drilling rigs in our fleet after adding our tenth BOSS rig during
the quarter. All 10 of our BOSS rigs are under contract, and we
currently have a total of 36 drilling rigs operating. Long-term
contracts (contracts with original terms ranging from six months to
two years in length) are in place for 15 of our drilling rigs. Of
the 15, seven of these contracts are up for renewal in the third
quarter of 2017, six in the fourth quarter of 2017, one is up for
renewal in 2018, and one in 2019.”
This table illustrates certain comparative results for the
periods indicated:
Three Months Ended
Three Months Ended Six Months Ended
Jun 30, Jun 30,
Jun 30, Mar 31,
Jun 30,
Jun 30,
2017 2016
Change 2017 2017
Change 2017 2016
Change Rigs Utilized 28.8
13.5 114 % 28.8 25.5
13 % 27.2 17.1 59
% Operating Profit Before Depreciation, Depletion, &
Amortization (MM) (1) $ 12.0 $ 5.0 140
% $ 12.0 $ 8.0 51 % $
20.0 $ 15.6 28 % (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, gas processed and liquids sold volumes per day
increased 7% and 6%, respectively, while gas gathered volumes per
day decreased 2%, as compared to the first quarter of 2017.
Operating profit (as defined in the footnote below) for the quarter
was $12.1 million, a decrease of 9% from the first quarter of
2017.
For the first six months of 2017, per day gas gathered, gas
processed and liquids sold volumes decreased 6%, 20% and 3%,
respectively, as compared to the first six months of 2016.
Operating profit (as defined in the footnote below) for the first
six months of 2017 was $25.3 million, an increase of 23% over the
first six months of 2016.
This table illustrates certain comparative results for the
periods indicated:
Three Months Ended
Three Months Ended Six Months Ended
Jun 30, Jun 30,
Jun 30, Mar 31,
Jun 30,
Jun 30,
2017 2016
Change 2017 2017
Change 2017 2016
Change Gas Gathering, Mcf/day 383,440
439,937 (13 )% 383,440
390,384 (2 )% 386,893
411,671 (6 )% Gas Processing, Mcf/day
135,002 161,619 (16 )%
135,002 126,559 7 %
130,804 164,333 (20 )% Liquids
Sold, Gallons/day 525,920
532,215 (1 )% 525,920
497,862 6 % 511,969
525,824 (3 )% Operating Profit Before Depreciation,
Depletion, & Amortization (MM) (1) $ 12.1
$ 12.5 (3 )% $ 12.1 $ 13.2 (9 )%
$ 25.3 $ 20.6 23 % (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: “Our midstream segment continued to reject ethane
at all processing facilities except Bellmon and Cashion, which have
a more attractive transportation and fractionation fee structure
for liquids. Processing and liquids sold volumes reflected quarter
over quarter improvement due to increasing processing volumes at
Hemphill and Cashion. Overall, our midstream segment continues to
post solid results as operator activity levels increase.”
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $806.1 million.
Long-term debt consisted of $641.2 million of senior subordinated
notes net of unamortized discount and debt issuance costs and
$164.9 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.
On April 4, 2017, Unit established an "at the market" equity
offering program under which it may offer and sell, from
time-to-time, up to an aggregate of $100 million for shares of its
common stock through "at the market" transactions. As of June 30,
2017, Unit has sold 787,547 shares for $18.6 million, net of
offering costs of $0.4 million. Approximately $81.0 million
remained available for sale under the program. Net proceeds from
the offering will be used to fund (or offset costs of)
acquisitions, future capital expenditures, repay amounts
outstanding under its revolving credit facility, and general
corporate purposes.
WEBCAST
Unit intends to use its website as a means of disclosing
material non-public information and for complying with its
disclosure obligations under Regulation FD. Those disclosures will
be included on its website in the 'Investor Information' sections.
Accordingly, investors should monitor that portion of the website,
in addition to following the press releases, SEC filings, and
public conference calls and webcasts.
Unit will webcast its second quarter earnings conference call
live over the Internet on August 3, 2017 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 before the start of the call to download and
install any necessary audio software. The slides Unit intends to
use during the call are available through the webcast link and also
on its website at http://www.unitcorp.com under 'Quick Links.' 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 listed 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, the
potential productive capability of its prospective plays including
the STACK play, the number of additional shares (if any) it may
sell under its "at the market" offering, 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, 2017
2016 2017 2016
Statement of Operations: Revenues: Oil and
natural gas $ 83,173 $ 69,190 $ 170,771 $ 127,464 Contract drilling
39,255 24,257 76,440 62,967 Gas gathering and processing
48,153 44,858 99,094
84,058 Total revenues 170,581 138,305
346,305 274,489 Expenses:
Operating costs: Oil and natural gas 32,758 33,331 61,962 66,677
Contract drilling 27,239 19,254 56,466 47,352 Gas gathering and
processing 36,042 32,381 73,746
63,447 Total operating costs 96,039 84,966
192,174 177,476 Depreciation, depletion, and amortization 50,080
52,878 97,012 108,468 Impairments — 74,291 — 112,120 General and
administrative 8,713 8,348 17,667 16,959 Gain on disposition of
assets (248 ) (477 ) (1,072 ) (669 )
Total operating expenses 154,584 220,006
305,781 414,354 Income
(loss) from operations 15,997 (81,701 )
40,524 (139,865 ) Other income (expense):
Interest, net (9,467 ) (10,606 ) (18,863 ) (20,223 ) Gain (loss) on
derivatives 8,902 (22,672 ) 23,633 (11,743 ) Other 6
1 9 (14 ) Total other income
(expense) (559 ) (33,277 ) 4,779
(31,980 ) Income (loss) before income taxes 15,438 (114,978
) 45,303 (171,845 ) Income tax expense (benefit): Deferred
6,379 (42,842 ) 20,315
(58,560 ) Total income taxes 6,379 (42,842 )
20,315 (58,560 ) Net income (loss) $
9,059 $ (72,136 ) $ 24,988 $ (113,285 ) Net
income (loss) per common share: Basic $ 0.18 $ (1.44 ) $ 0.49 $
(2.27 ) Diluted $ 0.17 $ (1.44 ) $ 0.49 $ (2.27 ) Weighted
average shares outstanding: Basic 51,366 50,074 50,832 49,977
Diluted 51,944 50,074 51,371 49,977
June 30, December 31,
2017 2016 Balance Sheet Data:
Current assets $ 109,504 $ 121,196 Total assets $ 2,523,310 $
2,479,303 Current liabilities $ 160,921 $ 164,915 Long-term debt $
806,092 $ 800,917 Other long-term liabilities and non-current
derivative liability $ 100,796 $ 103,479 Deferred income taxes $
211,038 $ 215,922 Shareholders’ equity $ 1,244,463 $ 1,194,070
Six Months Ended June 30,
2017 2016 Statement of Cash Flows
Data: Cash flow from operations before changes in
operating assets and liabilities $ 125,481 $ 77,734 Net change in
operating assets and liabilities (8,426 ) 54,982
Net cash provided by operating activities $ 117,055 $
132,716 Net cash used in investing activities $ (142,833 ) $
(77,386 ) Net cash provided by (used in) financing activities $
25,734 $ (55,191 )
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, 2017
and 2016. 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 (Loss) and Adjusted
Diluted Earnings (Loss) per Share Three Months
Ended Six Months Ended June 30, June 30,
2017 2016 2017
2016 (In thousands except earnings per share)
Adjusted net income (loss): Net income (loss) $ 9,059 $ (72,136 ) $
24,988 $ (113,285 ) Impairments (net of income tax) — 46,246 —
69,795 (Gain) loss on derivatives (net of income tax) (5,243 )
15,650 (13,036 ) 7,742 Settlements during the period of matured
derivative contracts (net of income tax) (252 ) 2,870
(865 ) 8,037 Adjusted net income (loss)
$ 3,564 $ (7,370 ) $ 11,087 $ (27,711 )
Adjusted diluted earnings (loss) per share: Diluted earnings (loss)
per share $ 0.17 $ (1.44 ) $ 0.49 $ (2.27 ) Diluted earnings per
share from impairments — 0.92 — 1.40 Diluted earnings per share
from (gain) loss on derivatives (0.10 ) 0.31 (0.25 ) 0.16 Diluted
earnings (loss) per share from settlements of matured derivative
contracts — 0.06 (0.02 )
0.16 Adjusted diluted income (loss) per share $ 0.07
$ (0.15 ) $ 0.22 $ (0.55 )
________________
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, 2017 2017
2016 2017 2016
(In thousands) Oil and natural gas $ 58,394 $ 50,415 $
35,859 $ 108,809 $ 60,787 Contract drilling 7,958 12,016 5,003
19,974 15,615 Gas gathering and processing 13,237
12,111 12,477 25,348
20,611 Total operating profit 79,589 74,542 53,339
154,131 97,013 Depreciation, depletion and amortization (46,932 )
(50,080 ) (52,878 ) (97,012 ) (108,468 ) Impairments —
— (74,291 ) —
(112,120 ) Total operating income (loss) 32,657 24,462 (73,830 )
57,119 (123,575 ) General and administrative (8,954 ) (8,713 )
(8,348 ) (17,667 ) (16,959 ) Gain on disposition of assets 824 248
477 1,072 669 Interest, net (9,396 ) (9,467 ) (10,606 ) (18,863 )
(20,223 ) Gain (loss) on derivatives 14,731 8,902 (22,672 ) 23,633
(11,743 ) Other 3 6 1
9 (14 ) Income (loss) before income taxes $
29,865 $ 15,438 $ (114,978 ) $ 45,303 $
(171,845 )
_________________
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, 2017
2017 2016 2017
2016 (In thousands except for operating days and
operating margins) Contract drilling revenue $ 37,185 $ 39,255
$ 24,257 $ 76,440 $ 62,967 Contract drilling operating cost
29,227 27,239 19,254 56,466 47,352
Operating profit from contract drilling 7,958 12,016 5,003 19,974
15,615 Add: Elimination of intercompany rig profit and bad debt
expense — 376 235 376 235
Operating profit from contract drilling before elimination of
intercompany rig profit and bad debt expense 7,958 12,392 5,238
20,350 15,850 Contract drilling operating days 2,291
2,625 1,230 4,916 3,108 Average daily
operating margin before elimination of intercompany rig profit and
bad debt expense $ 3,474 $ 4,721 $ 4,259 $ 4,139 $ 5,100
________________
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 Ended June 30, 2017
2016 (In thousands) Net cash provided
by operating activities $ 117,055 $ 132,716 Net change in operating
assets and liabilities 8,426 (54,982 ) Cash flow from
operations before changes in operating assets and liabilities $
125,481 $ 77,734
________________
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 Three Months
Ended Six Months Ended June 30, June 30,
2017 2016 2017
2016 (In thousands except earnings per share) Net
income (loss) $ 9,059 $ (72,136 ) $ 24,988 $ (113,285 ) Income
taxes 6,379 (42,842 ) 20,315 (58,560 ) Depreciation, depletion and
amortization 50,080 52,878 97,012 108,468 Amortization of debt
issuance costs and debt discount 539 528 1,075 1,054 Impairments —
74,291 — 112,120 Interest expense 9,467 10,606 18,863 20,223 (Gain)
loss on derivatives (8,902 ) 22,672 (23,633 ) 11,743 Settlements
during the period of matured derivative contracts (410 ) 5,052
(1,569 ) 12,192 Stock compensation plans 4,362 2,905 8,066 7,703
Other non-cash items 673 634 1,458 1,513 Gain on disposition of
assets (248 ) (477 ) (1,072 ) (669 )
Adjusted EBITDA $ 70,999 $ 54,111 $ 145,503 $
102,502 Diluted income (loss) per share $ 0.17 $
(1.44 ) $ 0.49 $ (2.27 ) Diluted earnings per share from income
taxes 0.12 (0.86 ) 0.40 (1.17 ) Diluted earnings per share from
depreciation, depletion and amortization 0.97 1.05 1.88 2.16
Diluted earnings per share from amortization of debt issuance costs
and debt discount 0.01 0.01 0.02 0.02 Diluted earnings per share
from impairments — 1.49 — 2.25 Diluted earnings per share from
interest expense 0.18 0.21 0.37 0.40 Diluted earnings per share
from (gain) loss on derivatives (0.17 ) 0.45 (0.46 ) 0.23 Diluted
earnings per share from settlements during the period of matured
derivative contracts (0.01 ) 0.10 (0.04 ) 0.25 Diluted earnings per
share from stock compensation plans 0.08 0.06 0.16 0.15 Diluted
earnings per share from other non-cash items 0.01 0.01 0.03 0.03
Diluted earnings per share from gain on disposition of assets
0.01 (0.01 ) (0.02 ) (0.01 )
Adjusted EBITDA per diluted share $ 1.37 $ 1.07 $
2.83 $ 2.04
________________
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.
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version on businesswire.com: http://www.businesswire.com/news/home/20170803005229/en/
Unit CorporationMichael D. Earl, 918-493-7700Vice President,
Investor Relationswww.unitcorp.com
Unit (NYSE:UNT)
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