Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the first quarter of 2015. Highlights for the
quarter include:
-
Record total production of 5.1 million barrels of oil equivalent
(MMBoe), a 22% increase over the first quarter of 2014 -
Oil and natural gas liquids (NGLs) production increased 27% over the
first quarter of 2014 -
Placed two BOSS drilling rigs into service and a third after the end
of the quarter -
Average dayrate of $20,130, a 3% increase over the first quarter of
2014 -
Completed an extension of the Pittsburgh Mills gathering system in
Pennsylvania -
Achieved record gas processed and gas gathered volumes per day with
increases of 26% and 10%, respectively, over the first quarter of 2014
FIRST QUARTER 2015 RESULTS
Because of significantly lower commodity prices in the first quarter of
2015, Unit recorded a $400.6 million pre-tax non-cash ceiling test write
down in the carrying value of the company’s oil and natural gas
properties. As a result, Unit recorded a net loss of $248.4 million, or
$5.07 per share, compared to net income of $56.9 million, or $1.17 per
diluted share, for the first quarter of 2014. Adjusted net income for
the quarter (which excludes the effect of non-cash commodity derivatives
and the effects of the write-down) was $3.7 million, or $0.08 per
diluted share (see Non-GAAP Financial Measures below). Total revenues
for the quarter were $255.1 million (42% oil and natural gas, 37%
contract drilling, and 21% mid-stream), compared to $388.0 million (49%
oil and natural gas, 27% contract drilling, and 24% mid-stream) for the
first quarter of 2014.
OIL AND NATURAL GAS SEGMENT INFORMATION
Total equivalent production per day for the quarter was 56.9 MBoe, an
increase of 22% and 7% over the first quarter of 2014 and the fourth
quarter of 2014, respectively. Liquids (oil and NGLs) production
represented 47% of total equivalent production for the quarter. Oil
production for the quarter was 12,197 barrels per day, an increase of
36% and 8% over the first quarter of 2014 and the fourth quarter of
2014, respectively. NGLs production for the quarter was 14,294 barrels
per day, an increase of 21% over the first quarter of 2014 and an
increase of 5% over the fourth quarter of 2014. Natural gas production
for the quarter was 182,203 thousand cubic feet (Mcf) per day, an
increase of 18% over the first quarter of 2014 and a 9% increase over
the fourth quarter of 2014.
Unit’s average realized per barrel equivalent price for the first
quarter was $21.99, a decrease of 47% from the first quarter of 2014 and
a decrease of 38% from the fourth quarter of 2014. Unit’s average
natural gas price for the first quarter of 2015 was $2.94 per Mcf, a
decrease of 31% from the first quarter of 2014 and a 21% decrease from
the fourth quarter of 2014. Unit’s average oil price for the quarter was
$48.47 per barrel, a decrease of 47% from the first quarter of 2014 and
a decrease of 40% from the fourth quarter of 2014. Unit’s average NGLs
price for the quarter was $8.65 per barrel, a 78% decrease from the
first quarter of 2014 and a decrease of 66% from the fourth quarter of
2014. All prices in this paragraph include the effects of derivative
contracts.
The following table summarizes this segment’s remaining 2015 derivative
contracts.
| Crude | |||||||||||||||
| Swap Volume | Collar Volume | Average | Average | Average | |||||||||||
| Period | Bbl/Day | Bbl/Day | Swap Price | Floor Price | Ceiling Price | ||||||||||
|
Apr – Dec 2015 |
1,000 | — | $95.00 | — | — | ||||||||||
|
May – Dec 2015 |
2,000 | $58.00 | $64.40 | ||||||||||||
| Natural Gas | |||||||||||||||
| Swap Volume | Collar Volume | Weighted Average | Weighted Average | Weighted Average | |||||||||||
| Period | MMBtu/Day | MMBtu/Day | Swap Price | Floor Price | Ceiling Price | ||||||||||
| Q2 2015 | 70,000 | 30,000 | $3.60 | $2.92 | $3.26 | ||||||||||
| Q3 2015 | 40,000 | 30,000 | $3.98 | $2.58 | $3.04 | ||||||||||
| Q4 2015 | 40,000 | — | $3.98 | — | — | ||||||||||
The following table illustrates this segment’s comparative production,
realized prices, and operating profit for the periods indicated:
| Three Months Ended | Three Months Ended | |||||||||||||||||||||||
|
Mar. 31, |
Mar. 31, |
Change |
Mar. 31, |
Dec. 31, |
Change | |||||||||||||||||||
| Oil and NGLs Production, MBbl | 2,384 | 1,875 | 27 | % | 2,384 | 2,296 | 4 | % | ||||||||||||||||
| Natural Gas Production, Bcf | 16.4 | 13.9 | 18 | % | 16.4 | 15.4 | 6 | % | ||||||||||||||||
| Production, MBoe | 5,117 | 4,184 | 22 | % | 5,117 | 4,868 | 5 | % | ||||||||||||||||
| Production, MBoe/day | 56.9 | 46.5 | 22 | % | 56.9 | 52.9 | 7 | % | ||||||||||||||||
| Avg. Realized Natural Gas Price, Mcfe (1) | $ | 2.94 | $ | 4.24 | (31 | )% | $ | 2.94 | $ | 3.72 | (21 | )% | ||||||||||||
| Avg. Realized NGL Price, Bbl(1) | $ | 8.65 | $ | 39.56 | (78 | )% | $ | 8.65 | $ | 25.28 | (66 | )% | ||||||||||||
| Avg. Realized Oil Price, Bbl (1) | $ | 48.47 | $ | 91.53 | (47 | )% | $ | 48.47 | $ | 81.34 | (40 | )% | ||||||||||||
| Realized Price / Boe (1) | $ | 21.99 | $ | 41.84 | (47 | )% | $ | 21.99 | $ | 35.73 | (38 | )% | ||||||||||||
|
Operating Profit Before Depreciation, Depletion, Amortization, & Impairment (MM) (2) |
$ | 60.9 | $ | 147.8 | (59 | )% | $ | 60.9 | $ | 111.0 | (45 | )% | ||||||||||||
(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.
At the end of the quarter, four Unit drilling rigs were operating for
this segment. Two were operating in the Southern Oklahoma Hoxbar Oil
Trend (SOHOT) and two were drilling in the Wilcox play, located in
southeast Texas. The current plan is to have four Unit drilling rigs
operating through the end of the second quarter at which time
adjustments may be made depending on factors such as commodity pricing,
service costs and/or well results.
In the SOHOT area, production increased 86% during the quarter as
compared to the fourth quarter of 2014. During the quarter, three new
horizontal operated Hoxbar wells were completed. Two wells were
completed in the Medrano member of the Hoxbar and one well in the
Marchand member. The 30 day initial production rate for the two Medrano
wells averaged 12.8 MMcfe per day of which approximately 30% consisted
of liquids. The Marchand well had a 30 day, 60 day, and 90 day
production rate of approximately 2,444 Boe per day, 2,063 Boe per day,
and 2,013 Boe per day, respectively, of which the production mix was 78%
oil, 12% NGLs, and 10% natural gas. The current plan for 2015 is to
average one to two Unit rigs drilling in the prospect, which should
equate to approximately 12 to 14 new horizontal Hoxbar completions. The
estimated 2015 capital spending for drilling in the SOHOT is
approximately $90 million.
In the Wilcox area, production was essentially unchanged during the
quarter as compared to the fourth quarter 2014 and increased 20% as
compared to the first quarter 2014. Production for the quarter was
hindered by delays in completing wells to allow for the negotiation of
better prices associated with the fracking of the wells. During the
quarter, three new Wilcox wells were completed. The BS R#1 (100% working
interest) is a new Wilcox discovery located in a separate fault block to
the south of the Gilly field. The well encountered approximately 238 net
feet of potential oil and gas pay from several Wilcox sands. Completion
operations have begun and the well is scheduled to be fracked in May.
The drilling operations of a confirmation well in the same fault block
as the BS R #1 has been finished and is awaiting completion. Two
horizontal Wilcox wells were also completed in the first quarter. Both
wells were recently fracked and are in the early stages of flow back.
Further discussion about the preliminary results for these two wells
will be given during the second quarter earnings call. The estimated
2015 capital spending for drilling in the Wilcox area is approximately
$100 million. The current plan is to utilize one to two Unit drilling
rigs in 2015, which should result in approximately eight vertical and
six horizontal Wilcox completions.
Larry Pinkston, Unit’s Chief Executive Officer and President, said:
“Despite the substantial reduction of our drilling activity during the
quarter, our oil and natural gas segment achieved a very nice quarter
over quarter production growth. Our 2015 production guidance is
approximately 18.6 to 19.0 MMBoe, an increase of 2% to 4% over 2014,
although actual results will continue to be subject to industry
conditions. Unit has a strong asset base, and we have a proven record of
weathering these unfavorable pricing cycles.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the quarter was 50.1, a
decrease of 26% from the first quarter of 2014, and a decrease of 38%
from the fourth quarter of 2014. Per day drilling rig rates for the
quarter averaged $20,130, an increase of 3% over the first quarter of
2014 and a 2% decrease from the fourth quarter of 2014. Average per day
operating margin for the quarter was $10,253 (before elimination of
intercompany drilling rig profit and bad debt expense of $2.9 million).
This compares to $7,870 (before elimination of intercompany drilling rig
profit and bad debt expense of $5.3 million) for the first quarter of
2014, an increase of 30%, or $2,383. As compared to $8,834 (before
elimination of intercompany drilling rig profit and bad debt expense of
$8.7 million) for the fourth quarter of 2014, first quarter 2015
operating margin increased 16% or $1,419 (in each case regarding
eliminating intercompany drilling rig profit and bad debt expense – see
Non-GAAP Financial Measures below). Average operating margins for the
first quarter of 2015 included early termination fees of approximately
$12.7 million, or $2,807 per day, from the cancellation of certain
long-term contracts, compared to no early termination fees during the
first quarter of 2014 and $0.2 million for the fourth quarter of 2014.
Larry Pinkston said: “Drilling rig demand continued to decline during
the first quarter because of the significant decrease in commodity
prices. During the quarter, our fourth and fifth BOSS drilling rig began
operating. With the addition of these two BOSS drilling rigs and one
that began operating after the end of the quarter, our current drilling
rig fleet now totals 92 drilling rigs, of which 30 are now working under
contract. Long-term contracts (contracts with original terms ranging
from six months to two years in length) are in place for 14 of the 30
drilling rigs. Of the 14 long term contracts, five are up for renewal
during the second quarter, two in the third quarter, and seven are up
for renewal in 2016 and 2017. Currently, we have six BOSS drilling rigs
operating, and two additional BOSS drilling rigs have been contracted to
be built for third party operators and are expected to be placed into
service later this year. We will delay fabrication of any additional
BOSS drilling rigs until contracts for those rigs are received.”
The following table illustrates certain comparative results from this
segment’s operations for the periods indicated:
| Three Months Ended | Three Months Ended | |||||||||||||||||||||||
|
Mar. 31, |
Mar. 31, |
Change |
Mar. 31, |
Dec. 31, |
Change | |||||||||||||||||||
| Rigs Utilized | 50.1 | 67.9 | (26 | )% | 50.1 | 80.9 | (38 | )% | ||||||||||||||||
| Operating Profit Before Depreciation & Impairment (MM) (1) | $ | 43.3 | $ | 42.8 | 1 | % | $ | 43.3 | $ | 57.1 | (24 | )% | ||||||||||||
(1) Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses excluding
depreciation and impairment.
MID-STREAM SEGMENT INFORMATION
For the quarter, per day gas gathered and gas processed volumes
increased 10% and 26%, respectively, while liquids sold volumes
decreased 20% as compared to the first quarter of 2014. Compared to the
fourth quarter of 2014, gas gathered and gas processed volumes per day
increased 2% and 15%, respectively, while liquids sold volumes per day
decreased 17%. Liquids sold volumes decreased during the quarter as a
result of several plant facilities operating in maximum ethane rejection
mode due to the very depressed pricing for ethane. Operating profit (as
defined in the footnote below) for the quarter was $9.8 million, a
decrease of 20% from the first quarter of 2014 and a decrease of 2% from
the fourth 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 | |||||||||||||||||
|
Mar. 31, |
Mar. 31, |
Change |
Mar. 31, |
Dec. 31, |
Change | |||||||||||||
| Gas Gathering, Mcf/day | 334,278 | 304,083 | 10% | 334,278 | 327,331 | 2% | ||||||||||||
| Gas Processing, Mcf/day | 189,160 | 150,042 | 26% | 189,160 | 163,979 | 15% | ||||||||||||
| Liquids Sold, Gallons/day | 568,876 | 712,225 | (20)% | 568,876 | 687,713 | (17)% | ||||||||||||
|
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (1) |
$ 9.8 | $ 12.2 | (20)% | $ 9.8 | $ 10.0 | (2)% | ||||||||||||
(1) Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses excluding
depreciation, amortization, and impairment.
Larry Pinkston said: “During the quarter, we completed the connection of
an additional third party operated well pad to our Pittsburgh Mills
gathering system. The well pad began producing at the beginning of the
second quarter. We continue to make progress on our Snowshoe project in
Centre County, Pennsylvania. The project consists of a seven-mile, 16
inch and 24 inch trunkline to gather Marcellus production for delivery
to an interstate pipeline. Construction of this project is expected to
be completed in the fourth quarter of 2015.”
FINANCIAL INFORMATION
Unit ended the first quarter with long-term debt of $883.6 million
(consisting of $646.3 million of senior subordinated notes net of
unamortized discount and $237.3 million of borrowings under its credit
agreement). Unit’s credit agreement provides that the amount Unit can
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 $725 million), but in either event
not to exceed $900 million. The credit agreement was amended after the
first quarter to provide for a new maturity date of April 2020 and
establish the current borrowing base amount noted above.
WEBCAST
Unit will webcast its first quarter earnings conference call live over
the Internet on May 7, 2015 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, 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 Highlights | |||||||||||
|
(In thousands except per share amounts) |
|||||||||||
| Three Months Ended | |||||||||||
| March 31, | |||||||||||
| 2015 | 2014 | ||||||||||
| Statement of Operations: | |||||||||||
| Revenues: | |||||||||||
| Oil and natural gas | $ | 106,069 | $ | 188,207 | |||||||
| Contract drilling | 95,077 | 106,600 | |||||||||
| Gas gathering and processing | 53,953 | 93,181 | |||||||||
| Total revenues | 255,099 | 387,988 | |||||||||
| Expenses: | |||||||||||
| Oil and natural gas: | |||||||||||
| Operating costs | 45,211 | 40,415 | |||||||||
| Depreciation, depletion, and amortization | 77,118 | 59,680 | |||||||||
| Impairment of oil and gas properties | 400,593 | — | |||||||||
| Contract drilling: | |||||||||||
| Operating costs | 51,746 | 63,804 | |||||||||
| Depreciation | 15,013 | 18,395 | |||||||||
| Gas gathering and processing: | |||||||||||
| Operating costs | 44,175 | 80,960 | |||||||||
| Depreciation and amortization | 10,694 | 9,591 | |||||||||
| General and administrative | 9,370 | 9,637 | |||||||||
| Gain on disposition of assets | (545 | ) | (9,426 | ) | |||||||
| Total operating expenses | 653,375 | 273,056 | |||||||||
| Income (loss) from operations | (398,276 | ) | 114,932 | ||||||||
| Other income (expense): | |||||||||||
| Interest, net | (7,240 | ) | (3,790 | ) | |||||||
| Gain (loss) on derivatives not designated as hedges | 6,586 | (18,366 | ) | ||||||||
| Other | (2 | ) | 120 | ||||||||
| Total other income (expense) | (656 | ) | (22,036 | ) | |||||||
| Income (loss) before income taxes | (398,932 | ) | 92,896 | ||||||||
| Income tax expense (benefit): | |||||||||||
| Current | 65 | 9,795 | |||||||||
| Deferred | (150,643 | ) | 26,156 | ||||||||
| Total income taxes | (150,578 | ) | 35,951 | ||||||||
| Net income (loss) | $ | (248,354 | ) | $ | 56,945 | ||||||
| Net income (loss) per common share: | |||||||||||
| Basic | $ | (5.07 | ) | $ | 1.17 | ||||||
| Diluted | $ | (5.07 | ) | $ | 1.17 | ||||||
| Weighted average shares outstanding: | |||||||||||
| Basic | 48,977 | 48,493 | |||||||||
| Diluted | 48,977 | 48,872 | |||||||||
| March 31, | December 31, | |||||||||
| 2015 | 2014 | |||||||||
| Balance Sheet Data: | ||||||||||
| Current assets | $ | 190,640 | $ | 252,491 | ||||||
| Total assets | $ | 4,050,905 | $ | 4,473,728 | ||||||
| Current liabilities | $ | 207,009 | $ | 304,171 | ||||||
| Long-term debt | $ | 883,584 | $ | 812,163 | ||||||
| Other long-term liabilities | $ | 142,597 | $ | 148,785 | ||||||
| Deferred income taxes | $ | 725,572 | $ | 876,215 | ||||||
| Shareholders’ equity | $ | 2,092,143 | $ | 2,332,394 | ||||||
| Three Months Ended March 31, | |||||||||||
| 2015 | 2014 | ||||||||||
| Statement of Cash Flows Data: | |||||||||||
| Cash flow from operations before changes | |||||||||||
| in operating assets and liabilities | $ | 116,304 | $ | 178,224 | |||||||
| Net change in operating assets and liabilities | 44,005 | (54,764 | ) | ||||||||
| Net cash provided by operating activities | $ | 160,309 | $ | 123,460 | |||||||
| Net cash used in investing activities | $ | (231,027 | ) | $ | (160,518 | ) | |||||
| Net cash provided by financing activities | $ | 70,533 | $ | 19,517 | |||||||
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 net income and earnings per share including
impairment adjustments and the effect of the cash settled commodity
derivatives, its drilling segment’s average daily operating margin
before elimination of intercompany drilling rig profit and bad debt
expense, and its cash flow from operations before changes in operating
assets and liabilities.
Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three months ended March 31, 2015 and 2014.
Non-GAAP financial measures should not be considered by themselves or a
substitute for results reported in accordance with GAAP.
| Unit Corporation | |||||||||||
|
Reconciliation of Adjusted Net Income and Adjusted Diluted |
|||||||||||
|
|
|||||||||||
| Three Months Ended | |||||||||||
| March 31, | |||||||||||
| 2015 | 2014 | ||||||||||
|
|
(In thousands except per share amounts) |
||||||||||
| Adjusted net income: | |||||||||||
| Net income (loss) | $ | (248,354 | ) | $ | 56,945 | ||||||
| Impairment adjustment (net of income tax) | 249,369 | — | |||||||||
| (Gain) loss on derivatives not designated as hedges | |||||||||||
| (net of income tax) | (4,024 | ) | 11,258 | ||||||||
| Settlements during the period of matured | |||||||||||
| derivative contracts (net of income tax) | 6,728 | (5,438 | ) | ||||||||
| Adjusted net income | $ | 3,719 | $ | 62,765 | |||||||
| Adjusted diluted earnings per share: | |||||||||||
| Diluted earnings (loss) per share | $ | (5.07 | ) | $ | 1.17 | ||||||
| Diluted earnings per share from the impairments | 5.09 | — | |||||||||
|
Diluted earnings per share from the (gain) loss |
|||||||||||
| on derivatives | (0.08 |
) |
0.23 | ||||||||
| Diluted earnings (loss) per share from the | |||||||||||
| settlements of matured derivative contracts | 0.14 | (0.11 | ) | ||||||||
| Adjusted diluted earnings per share | $ | 0.08 | $ | 1.29 | |||||||
________________
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 Average Daily Operating Margin Before |
|||||||||||||
| Three Months Ended | |||||||||||||
| December 31, | March 31, | ||||||||||||
| 2014 | 2015 | 2014 | |||||||||||
|
|
(In thousands except operating days |
||||||||||||
| Contract drilling revenue | $ | 134,987 | $ | 95,077 | $ | 106,600 | |||||||
| Contract drilling operating cost | 77,908 | 51,746 | 63,804 | ||||||||||
| Operating profit from contract drilling | 57,079 | 43,331 | 42,796 | ||||||||||
| Add: | |||||||||||||
| Elimination of intercompany rig profit | |||||||||||||
| and bad debt expense | 8,669 | 2,910 | 5,313 | ||||||||||
| Operating profit from contract drilling before | |||||||||||||
| elimination of intercompany rig profit | |||||||||||||
| and bad debt expense | 65,748 | 46,241 | 48,109 | ||||||||||
| Contract drilling operating days | 7,443 | 4,510 | 6,113 | ||||||||||
| Average daily operating margin before elimination of | |||||||||||||
| intercompany rig profit and bad debt expense | $ | 8,834 | $ | 10,253 | $ | 7,870 | |||||||
________________
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 |
||||||||||
| Three Months Ended
March 31, |
||||||||||
| 2015 | 2014 | |||||||||
| (In thousands) | ||||||||||
| Net cash provided by operating activities | $ | 160,309 | $ | 123,460 | ||||||
| Net change in operating assets and liabilities | (44,005 | ) | 54,764 | |||||||
| Cash flow from operations before changes | ||||||||||
| in operating assets and liabilities | $ | 116,304 | $ | 178,224 | ||||||
________________
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
Michael D. Earl, 918-493-7700
Vice President,
Investor Relations
www.unitcorp.com
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