Unit Corporation (NYSE: UNT) reported today its net income of $32.2
million, or $0.68 per diluted share, for the three months ended June 30,
2010, compared to net income of $32.0 million, or $0.68 per diluted
share, for the three months ended June 30, 2009. Total revenues for the
second quarter of 2010 were $204.6 million (35% contract drilling, 45%
oil and natural gas, and 18% mid-stream), compared to total revenues for
the second quarter of 2009 of $164.1 million (30% contract drilling, 55%
oil and natural gas, and 14% mid-stream).
For the first six months of 2010, Unit reported net income of $68.3
million, or $1.43 per diluted share, compared to a net loss of $115.5
million, or $2.46 per diluted share, for the six months ended June 30,
2009. Included in the 2009 results was a noncash ceiling test write down
of $281.2 million ($175.1 million after tax, or $3.72 per diluted share)
that occurred in the first quarter. The ceiling test write down was
required to reduce the carrying value of the company’s oil and natural
gas properties because of significantly lower commodity prices at the
end of the first quarter 2009. If the ceiling test write down had not
been required, net income for the first six months of 2009 would have
been $59.6 million, or $1.26 per diluted share (see Non-GAAP Financial
Measures below). Total revenues for the first six months of 2010 were
$411.2 million (32% contract drilling, 46% oil and natural gas, and 19%
mid-stream), compared to $365.1 million (38% contract drilling, 49% oil
and natural gas, and 12% mid-stream) for the first six months of 2009.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the second quarter of 2010
was 58.1, an increase of 84% from the second quarter of 2009, and an
increase of 14% from the first quarter of 2010. Contract drilling per
day rig rates for the second quarter of 2010 averaged $14,915, down 14%,
or $2,420, from the second quarter of 2009, and up 6%, or $788, from the
first quarter of 2010. Average per day operating margins for the second
quarter of 2010 were $5,101 (before elimination of intercompany drilling
rig profit of $1.5 million) as compared to $7,138 (before elimination of
intercompany drilling rig profit of $0.4 million) for the second quarter
of 2009, down 29%, and compared to $4,435 (before elimination of
intercompany drilling rig profit and bad debt expense of $0.4 million)
for the first quarter 2010, up 15% or $666 (in each case with regard to
the elimination of intercompany drilling rig profit see Non-GAAP
Financial Measures below). Included in the average operating margin
amounts for the second quarter 2010, the second quarter 2009, and first
quarter 2010 was an approximate per day amount of $6, $163, and $28,
respectively, resulting from early termination fees associated with the
cancellation of long-term contracts. Excluding these early termination
fees, average per day operating margins for the second quarter of 2010
were $5,095, an increase of $688 per day or 16% as compared to $4,407
for the first quarter of 2010.
For the first six months of 2010, Unit averaged 54.5 drilling rigs
working, up 29% from 42.1 drilling rigs working during the first six
months of 2009. Average per day operating margins for the first six
months of 2010 were $4,791 (before elimination of intercompany drilling
rig profit of $1.8 million) as compared to $7,807 (before elimination of
intercompany drilling rig profit of $1.1 million) for the first six
months of 2009, a decrease of 39% (in each case with regard to the
elimination of intercompany drilling rig profit see Non-GAAP Financial
Measures below). Included in the average operating margin amounts for
the first six months of 2010 and 2009 was an approximate per day amount
of $15 and $61, respectively, resulting from early termination fees
associated with the cancellation of long-term contracts. Excluding early
termination fees, average operating margins for the first six months of
2010 were $4,776 per day, a decrease of $2,970 per day or 38% as
compared to $7,746 per day for the first six months of 2009.
The following table illustrates this segment’s drilling rig count at the
end of each period and average utilization rate during the period:
| 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | ||||||||||||||||||||
| Rigs | 123 | 125 | 130 | 130 | 131 | 131 | 132 | 131 | 131 | |||||||||||||||||||
| Utilization | 47% | 40% | 28% | 26% | 24% | 40% | 74% | 85% | 80% | |||||||||||||||||||
Larry Pinkston, Unit’s Chief Executive Officer and President, said:
‘During the second quarter, we experienced an increase in the demand for
our drilling rigs and dayrates, especially on drilling rigs drilling
horizontal wells. We completed the previously announced sale of eight of
our idle mechanical drilling rigs. We are using the sales proceeds to
refurbish and upgrade certain drilling rigs in our fleet that we intend
to target toward horizontal drilling activity. With the completed sale,
our drilling rig fleet now totals 123. Currently, 71 of the 123 drilling
rigs are under contract. Long-term contracts for which the original
terms ranged from six months to two years in length are in place for 42
of the 71 drilling rigs currently under contract for work. Thirteen of
these contracts are up for renewal during 2010, 28 are up for renewal
during 2011 and one is up for renewal in 2012.’
OIL AND NATURAL GAS SEGMENT INFORMATION
-
Drilled 39 and 66 gross wells during the 2010 second quarter and first
six months, respectively. -
Completed a property acquisition that includes approximately 45,000
net acres and 11 producing oil wells. - Sold a natural gas pipeline of which we owned 60%.
-
Approximately 68% of anticipated natural gas production and 65% of
anticipated crude oil production for 2010 is hedged. -
Plan to drill 175 wells during 2010 with a revised production estimate
of 62.0 to 63.0 Bcfe.
Second quarter 2010 production was 321,000 barrels of oil, in comparison
to 348,000 barrels of oil in the second quarter of 2009, down 8%.
Natural gas liquids (NGLs) production during the second quarter of 2010
was 388,000 barrels in comparison to 391,000 barrels in the second
quarter of 2009, down 1%. Second quarter 2010 natural gas production was
down 12% to 9.7 billion cubic feet (Bcf) compared to 11.0 Bcf for the
comparable quarter of 2009. Second quarter 2010 equivalent production
totaled 14.0 Bcfe, down 10% from the second quarter of 2009. Total
production for the first six months of 2010 was 28.1 Bcfe, down 12% over
the 31.7 Bcfe produced during the first six months of 2009.
Unit’s average natural gas price, including the effects of hedges, for
the second quarter of 2010 increased 2% to $5.62 per thousand cubic feet
(Mcf) as compared to $5.49 per Mcf for the second quarter of 2009.
Unit’s average oil price, including the effects of hedges, for the
second quarter of 2010 was $66.93 per barrel compared to $54.84 per
barrel for the second quarter of 2009, up 22%, and Unit’s average NGLs
price, including the effects of hedges, for the second quarter of 2010
was $33.37 per barrel compared to $23.88 per barrel for the second
quarter of 2009, up 40%. For the first six months of 2010, Unit’s
average natural gas price, including the effects of hedges, increased 6%
to $5.79 per Mcf as compared to $5.47 per Mcf for the first six months
of 2009. Unit’s average oil price, including the effects of hedges, for
the first six months of 2010 was $67.12 per barrel compared to $52.69
per barrel during the first six months of 2009, a 27% increase. Unit’s
average NGLs price, including the effects of hedges, for the first six
months of 2010 was $38.01 per barrel compared to $21.29 per barrel
during the first six months of 2009, a 79% increase.
For 2010, approximately 68% of the company’s anticipated average daily
natural gas production is hedged, 65% of its anticipated daily oil
production is hedged, and 11% of its anticipated daily natural gas
liquids production is hedged. The natural gas production is hedged under
swap contracts at a comparable average NYMEX price of $6.95. The average
basis differential for the swaps is ($0.66). Of the oil hedges, 60% are
under swap contracts at an average price of $61.36 per barrel and 40%
are under a collar contract with a floor of $67.50 per barrel and a
ceiling of $81.53 per barrel. The natural gas liquids production is
hedged under swap contracts at an average price of $41.12 per barrel.
For 2011, 15,000 MMBtu per day of the company’s natural gas production
is hedged, 2,500 Bbls per day of its oil production is hedged and 504
Bbls per day of its natural gas liquids production is hedged. The
natural gas production is hedged under swap contracts at a comparable
average NYMEX price of $5.56. The average basis differential for the
swaps is ($0.14). The oil production is hedged under swap contracts at
an average price of $80.32 per barrel. The natural gas liquids
production is hedged under swap contracts at an average price of $40.74
per barrel.
For 2012, approximately 15,000 MMBtu per day of the company’s natural
gas production is hedged and 1,500 Bbls per day of its oil production is
hedged. The natural gas production is hedged under swap contracts at a
comparable average NYMEX price of $5.90. The average basis differential
for the swaps is ($0.28). The oil production is hedged under swap
contracts at an average price of $82.49 per barrel.
The following table illustrates this segment’s production and certain
results for the periods indicated:
| 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | ||||||||||||||||||||
| Production, Bcfe |
14.0 |
14.1 |
14.3 |
14.7 |
15.4 |
16.3 |
16.8 |
15.9 |
16.0 |
|||||||||||||||||||
| Production, MMcfe/day |
153.3 |
156.8 |
155.8 |
159.4 |
169.6 |
180.9 |
182.6 |
172.4 |
175.3 |
|||||||||||||||||||
| Realized price, Mcfe (1) |
$6.37 |
$6.82 |
$6.12 |
$5.92 |
$5.75 |
$5.48 |
$6.21 |
$9.49 |
$10.19 |
|||||||||||||||||||
| Wells Drilled |
39 |
27 |
37 |
21 |
16 |
21 |
67 |
82 |
72 |
|||||||||||||||||||
| Success Rate |
92% |
96% |
92% |
90% |
100% |
90% |
90% |
89% |
90% |
|||||||||||||||||||
|
(1) Realized price includes oil, natural gas liquids, natural gas |
||||||||||||||||||||||||||||
During the second quarter of 2010, this segment drilled 39 wells with a
success rate of 92% compared to 16 wells with a 100% success rate during
the second quarter of 2009.
In the Bakken play in North Dakota, Unit owns a 25% working interest in
the Marty #1-20 which is currently flowing back after fracture
stimulation at rates of approximately 1,500 barrels of oil per day and
1.6 MMcf per day. The well was drilled with a 5,736′ lateral and
fracture stimulated in 15 stages. This is the second high volume oil
well in the Williams County, ND Stockyard Creek Prospect where Unit owns
approximately 11,500 gross (2,700 net) acres and expects to have one
drilling rig operating during the remainder of 2010. In McKenzie County,
ND, Unit owns a 16% working interest in the Dodge #4-6/7 HR which was
recently completed at rates of approximately 2,465 barrels of oil per
day and 1.6 MMcf per day. The well was drilled with an 8,846′ lateral
and fracture stimulated in 24 stages. Unit owns approximately 27,000
gross (5,400 net) acres in the Antelope Prospect and anticipates one rig
drilling for the rest of this year.
In the Haynesville Shale play in Shelby County, TX, Unit owns a 55%
working interest in the Smith #1H which was recently completed flowing
at rates of 3.5 MMcf per day with 5,800 pounds of flowing tubing
pressure. The well is being curtailed due to current pipeline
constraints which are expected to be resolved in September. The well was
drilled with a lateral of 3,300′ and fracture stimulated with eight
stages. Unit owns approximately 16,000 gross (11,000 net) acres in the
prospect area and anticipates drilling two additional wells in 2010.
In June, this segment closed the acquisition of oil and natural gas
properties from certain unaffiliated third parties for approximately
$75.0 million in cash, subject to post-closing adjustments. The
acquisition includes approximately 45,000 net acres and 11 producing oil
wells and is focused on the Marmaton horizontal oil play located
primarily in Beaver County, Oklahoma. This acquisition, along with
Unit’s existing leasehold position in this Marmaton play, provides Unit
with more than 56,000 net undeveloped leasehold acres in this play.
Proved developed producing (PDP) net reserves associated with the 11
acquired producing wells is approximately 900,000 barrels of oil
equivalent (Boe) – consisting of 600,000 barrels of oil, 200,000 barrels
of natural gas liquids (NGLs), and 700 million cubic feet (MMcf) of
natural gas. Net production from these wells in April 2010 averaged
approximately 850 barrels of oil per day and 1.0 MMcf of natural gas per
day.
Pinkston said: ‘This acquisition complements the presence that we
already have in the Anadarko Basin, one of our core areas of operations.
It also adds oil production and reserves to our existing portfolio and
is in line with our focus on oil and rich gas opportunities. We
anticipate working two to three drilling rigs in this play in which we
have identified approximately 300 potential well locations with expected
average reserves per well of 120,000 barrels of oil equivalent.
Projected average completed well costs for wells in this play are
approximately $2.0 million. Also during the second quarter, we sold a
gas pipeline, located in the Haynesville Shale play in Shelby County,
Texas, for $17 million, of which we owned 60%.’
‘The first half of 2010 has been a challenging period for us in
establishing the momentum planned for our 2010 drilling program. During
the first and second quarters of 2010, we drilled 27 wells and 39 wells,
respectively. Our first quarter 2010 drilling activity was slowed down
by unusually wet weather, especially in the Texas Panhandle Granite Wash
play, and operational delays as we transition to drilling primarily
horizontal wells. While the number of wells drilled increased 44% from
the first quarter to the second quarter, 46% of the wells drilled have
not come online. The delays in getting wells online are primarily due to
delays in fracture stimulation services and connections to gathering
systems. Currently, we anticipate these delays will continue throughout
the year due to limited availability of these services. As a result, we
are revising our 2010 production guidance to approximately 62.0 to 63.0
Bcfe, with actual results subject to the timing of third party services.
The number of wells we plan to participate in drilling and the level of
capital expenditures remains unchanged for 2010 at 175 wells and $365
million, respectively.’
MID-STREAM SEGMENT INFORMATION
-
Increased second quarter 2010 liquids sold per day volumes and
processing volumes per day by 17% and 10%, respectively, over second
quarter of 2009. -
In the process of adding two new processing plants to existing
gathering systems.
Second quarter of 2010 per day processing volumes were 82,699 MMBtu
while liquids sold volumes were 279,736 gallons per day, an increase of
10% and 17%, respectively, over second quarter of 2009. Second quarter
2010 per day gathering volumes were 183,858 MMBtu, down 2% over the
second quarter of 2009. Operating profit (as defined in the Selected
Financial and Operational Highlights) for the second quarter was $7.4
million, an increase of $3.4 million from the second quarter of 2009,
due primarily to increased liquids prices, which resulted in increased
processing margins.
For the first six months of 2010, processing volumes of 79,623 MMBtu per
day and liquids sold volumes of 266,793 gallons per day increased 7% and
17%, respectively, from the first six months of 2009. Gathering volumes
for the first six months of 2010 were 181,998 MMBtu per day, a 4%
decrease from the first six months of 2009.
The following table illustrates certain results from this segment’s
operations for the periods indicated:
| 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | ||||||||||||||||||||
| Gas gathered | 183,858 | 180,117 | 177,145 | 179,047 | 187,666 | 192,320 | 187,585 | 195,914 | 205,397 | |||||||||||||||||||
| MMBtu/day | ||||||||||||||||||||||||||||
| Gas processed | 82,699 | 76,513 | 77,501 | 77,923 | 75,481 | 72,650 | 72,491 | 71,260 | 67,545 | |||||||||||||||||||
| MMBtu/day | ||||||||||||||||||||||||||||
| Liquids sold | 279,736 | 253,707 | 263,668 | 251,830 | 239,121 | 218,762 | 197,428 | 199,805 | 202,130 | |||||||||||||||||||
| Gallons/day | ||||||||||||||||||||||||||||
Unit’s mid-stream segment operates three natural gas treatment plants,
owns and operates eight processing plants, 33 active gathering systems
and approximately 846 miles of pipeline.
Pinkston said: ‘Gas processed volumes, liquids sold volumes as well as
gas gathered volumes all continued to increase and remained strong in
the second quarter. We are in the process of adding two new processing
plants to existing gathering systems. Construction on the 50.0 MMcf per
day processing plant at our Hemphill facility in the Texas Panhandle is
proceeding as planned with a completion date scheduled for the fourth
quarter of this year. We are also in the process of adding a second
processing plant, a 6.0 MMcf per day plant, at our Remington gathering
facility in Osage County, Oklahoma. That plant should be completed and
placed in service during the third quarter of 2010. We are continuing
our activities in the Appalachian Basin with several existing projects
moving forward as well as exploring various new opportunities that arise
in the area.’
FINANCIAL INFORMATION
Unit ended the second quarter of 2010 with working capital of $47.2
million, long-term debt of $130.0 million, and a debt to capitalization
ratio of 7%. Under the company’s credit facility, the amount available
to be borrowed is the lesser of the amount the company elects as the
commitment amount (currently $325 million) or the value of the borrowing
base as determined by the lenders under the credit facility (currently
$500 million), but in either event not to exceed the maximum credit
facility amount of $400 million.
MANAGEMENT COMMENT
Larry Pinkston said: ‘The challenges to our industry remain, yet we are
experiencing and benefiting from the increases in demand for drilling by
exploration and production companies and are continuing to refurbish and
upgrade certain drilling rigs in our fleet. As evidenced by our recent
oil and natural gas property acquisition, our focus continues to be on
developing areas of oil or rich gas. While our 2010 exploration
activities have started slower than we would like, we believe the
results of our efforts will be evident throughout the second half of the
year and carry into 2011.’
WEBCAST
Unit will webcast its second quarter earnings conference call live over
the Internet on August 3, 2010 at 10:00 a.m. Central Time (11:00 a.m.
Eastern). To listen to the live call, please go to www.unitcorp.com
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 twelve months.
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.
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. A number of risks and uncertainties could cause actual
results to differ materially from these statements, including the impact
that the current decline in wells being drilled will have on production
and drilling rig utilization, 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, as well as 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, availability and timing of obtaining third party
services used in the drilling or completion of its oil and gas wells,
anticipated oil and natural gas prices, the number of wells to be
drilled by the Company’s exploration segment, development, operational,
implementation and opportunity risks, possible delays caused by limited
availability of third party services needed in the course of 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 as a result of new information,
future events or otherwise.
| Unit Corporation | ||||||||||||||||||
| Selected Financial and Operations Highlights | ||||||||||||||||||
|
(In thousands except per share and operations data) |
||||||||||||||||||
| Three Months Ended | Six Months Ended | |||||||||||||||||
| June 30, | June 30, | |||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||||
| Statement of Operations: | ||||||||||||||||||
| Revenues: | ||||||||||||||||||
| Contract drilling | $ | 72,061 | $ | 49,883 | $ | 132,915 | $ | 138,582 | ||||||||||
| Oil and natural gas | 91,136 | 89,601 | 190,189 | 178,505 | ||||||||||||||
| Gas gathering and processing | 36,344 | 23,233 | 77,479 | 45,376 | ||||||||||||||
| Other | 5,062 | 1,357 | 10,570 | 2,673 | ||||||||||||||
| Total revenues | 204,603 | 164,074 | 411,153 | 365,136 | ||||||||||||||
| Expenses: | ||||||||||||||||||
| Contract drilling: | ||||||||||||||||||
| Operating costs | 46,541 | 29,779 | 87,441 | 80,109 | ||||||||||||||
| Depreciation | 16,445 | 10,261 | 30,231 | 22,880 | ||||||||||||||
| Oil and natural gas: | ||||||||||||||||||
| Operating costs | 23,817 | 17,249 | 48,851 | 42,065 | ||||||||||||||
|
Depreciation, depletion and amortization |
26,319 | 26,149 | 51,655 | 64,155 | ||||||||||||||
|
Impairment of oil and natural gas properties |
— |
— |
— |
281,241 |
||||||||||||||
| Gas gathering and processing: | ||||||||||||||||||
| Operating costs | 28,938 | 19,199 | 61,664 | 39,876 | ||||||||||||||
|
Depreciation and amortization |
3,982 | 4,110 | 7,923 | 8,171 | ||||||||||||||
| General and administrative | 6,456 | 5,493 | 12,735 | 11,582 | ||||||||||||||
| Interest, net | — | 61 | — | 538 | ||||||||||||||
| Total expenses | 152,498 | 112,301 | 300,500 | 550,617 | ||||||||||||||
|
Income (Loss) Before Income Taxes |
52,105 | 51,773 | 110,653 | (185,481 | ) | |||||||||||||
| Income Tax Expense (Benefit): | ||||||||||||||||||
| Current | 3,825 | 1,247 | 6,065 | 1,247 | ||||||||||||||
| Deferred | 16,105 | 18,495 | 36,260 | (71,266 | ) | |||||||||||||
| Total income taxes | 19,930 | 19,742 | 42,325 | (70,019 | ) | |||||||||||||
| Net Income (Loss) | $ | 32,175 | $ | 32,031 | $ | 68,328 | $ | (115,462 | ) | |||||||||
|
Net Income (Loss) per Common Share: |
||||||||||||||||||
| Basic | $ | 0.68 | $ | 0.68 | $ | 1.45 | $ | (2.46 | ) | |||||||||
| Diluted | $ | 0.68 | $ | 0.68 | $ | 1.43 | $ | (2.46 | ) | |||||||||
|
Weighted Average Common Shares Outstanding: |
||||||||||||||||||
| Basic | 47,171 | 47,008 | 47,146 | 46,965 | ||||||||||||||
| Diluted | 47,656 | 47,358 | 47,671 | 46,965 | ||||||||||||||
| June 30, | December 31, | |||||||||
| 2010 | 2009 | |||||||||
| Balance Sheet Data: | ||||||||||
| Current assets | $ | 156,391 | $ | 128,095 | ||||||
| Total assets | $ | 2,461,706 | $ | 2,228,399 | ||||||
| Current liabilities | $ | 109,241 | $ | 105,147 | ||||||
| Long-term debt | $ | 130,000 | $ | 30,000 | ||||||
| Other long-term liabilities | $ | 82,234 | $ | 81,126 | ||||||
| Deferred income taxes | $ | 484,058 | $ | 446,316 | ||||||
| Shareholders’ equity | $ | 1,656,173 | $ | 1,565,810 | ||||||
| Six Months Ended June 30, | |||||||||
| 2010 | 2009 | ||||||||
| Statement of Cash Flows Data: | |||||||||
|
Cash Flow From Operations before Changes in Operating Assets and |
$ | 191,814 | $ | 198,208 | |||||
| Net Change in Operating Assets and Liabilities | (14,047 | ) | 110,634 | ||||||
|
Net Cash Provided by Operating Activities |
$ | 177,767 | $ | 308,842 | |||||
| Net Cash Used in Investing Activities | $ | (277,265 | ) | $ | (181,965 | ) | |||
|
Net Cash Provided by (Used in) Financing Activities |
$ |
100,119 |
$ |
(126,504 | ) | ||||
| Three Months Ended | Six Months Ended | ||||||||||||||||||||
| June 30, | June 30, | ||||||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | ||||||||||||||||||
| Contract Drilling Operations Data: | |||||||||||||||||||||
| Rigs Utilized | 58.1 | 31.6 | 54.5 | 42.1 | |||||||||||||||||
| Operating Margins (2) | 35 | % | 40 | % | 34 | % | 42 | % | |||||||||||||
| Operating Profit Before Depreciation (2) ($MM) | $ | 25.5 | $ | 20.1 | $ | 45.5 | $ | 58.5 | |||||||||||||
| Oil and Natural Gas Operations Data: | |||||||||||||||||||||
| Production: | |||||||||||||||||||||
| Oil – MBbls | 321 | 348 | 623 | 691 | |||||||||||||||||
| Natural Gas Liquids – MBbls | 388 | 391 | 765 | 784 | |||||||||||||||||
| Natural Gas – MMcf | 9,701 | 10,999 | 19,735 | 22,861 | |||||||||||||||||
| Average Prices: | |||||||||||||||||||||
| Oil price per barrel received | $ | 66.93 | $ | 54.84 | $ | 67.12 | $ | 52.69 | |||||||||||||
| Oil price per barrel received, excluding hedges | $ | 74.49 | $ | 53.61 | $ | 75.08 | $ | 46.11 | |||||||||||||
| NGLs price per barrel received | $ | 33.37 | $ | 23.88 | $ | 38.01 | $ | 21.29 | |||||||||||||
| NGLs price per barrel received, excluding hedges | $ | 33.10 | $ | 23.88 | $ | 37.88 | $ | 21.29 | |||||||||||||
| Natural Gas price per Mcf received | $ | 5.62 | $ | 5.49 | $ | 5.79 | $ | 5.47 | |||||||||||||
| Natural Gas price per Mcf received, excluding hedges | $ | 3.72 | $ | 2.71 | $ | 4.44 | $ | 3.11 | |||||||||||||
|
Operating Profit Before DD&A and Impairment (2) ($MM) |
$ | 67.3 | $ | 72.4 | $ | 141.3 | $ | 136.4 | |||||||||||||
| Mid-Stream Operations Data: | |||||||||||||||||||||
| Gas Gathering – MMBtu/day | 183,858 | 187,666 | 181,998 | 189,980 | |||||||||||||||||
| Gas Processing – MMBtu/day | 82,699 | 75,481 | 79,623 | 74,074 | |||||||||||||||||
| Liquids Sold – Gallons/day | 279,736 | 239,121 | 266,793 | 228,998 | |||||||||||||||||
|
Operating Profit Before Depreciation and Amortization (2) ($MM) |
$ | 7.4 | $ | 4.0 | $ | 15.8 | $ | 5.5 | |||||||||||||
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(1) The company considers its cash flow from operations before |
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(2) Operating profit before depreciation is calculated by taking |
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Non-GAAP Financial Measures
We report our financial results in accordance with generally accepted
account principles (‘GAAP’). We believe certain non-GAAP performance
measures provide users of our financial information and our management
additional meaningful information to evaluate the performance of our
company.
This press release includes net income excluding the effect of the
impairment of our oil and natural gas properties, earnings per share
excluding the effect of the impairment of our oil and natural gas
properties, cash flow from operations before changes in working capital
and our drilling segment’s average daily operating margin before
elimination of drilling rig profit.
Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three and six months ended June 30, 2010 and
2009. Non-GAAP financial measures should not be considered by themselves
or a substitute for our results reported in accordance with GAAP.
| Unit Corporation | |||||||||||||||||
| Reconciliation of Net Income and Earnings per Share | |||||||||||||||||
| Excluding the Effect of Impairment of Oil and Natural Gas Properties |
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| Three Months Ended | Six Months Ended | ||||||||||||||||
| June 30, | June 30, | ||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | ||||||||||||||
| (In thousands) | |||||||||||||||||
|
Net income excluding impairment of oil and natural gas properties: |
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| Net income (loss) | $ | 32,175 | $ | 32,031 | $ | 68,328 | $ | (115,462 | ) | ||||||||
| Add: | |||||||||||||||||
|
Impairment of oil and natural gas properties (net of income tax) |
— | — | — | 175,072 | |||||||||||||
|
Net income excluding impairment of oil and natural gas properties |
$ | 32,175 | $ | 32,031 | $ | 68,328 | $ | 59,610 | |||||||||
|
Diluted earnings per share excluding impairment of oil and natural |
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| Diluted earnings per share | $ | 0.68 | $ | 0.68 | $ | 1.43 | $ | (2.46 | ) | ||||||||
| Add: | |||||||||||||||||
|
Diluted earnings per share from impairment of oil and natural gas |
— | — | — | 3.72 | |||||||||||||
|
Diluted earnings per share excluding impairment of oil and natural |
$ | 0.68 | $ | 0.68 | $ | 1.43 | $ | 1.26 | |||||||||
We have included the net income excluding impairment of oil and natural
gas properties and diluted earnings per share excluding impairment of
oil and natural gas properties because:
-
We use the adjusted net income to evaluate the operational performance
of the company. -
The adjusted net income is more comparable to earnings estimates
provided by securities analyst. -
The impairment of oil and natural gas properties does not occur on a
recurring basis and the amount and timing of impairments cannot be
reasonably estimated for budgeting purposes and is therefore typically
not included for forecasting operating results.
| Unit Corporation | ||||||||||
| Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities |
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| Six Months Ended | ||||||||||
| June 30, | ||||||||||
| 2010 | 2009 | |||||||||
| (In thousands) | ||||||||||
| Net cash provided by operating activities | $ | 177,767 | $ | 308,842 | ||||||
| Subtract: | ||||||||||
| Net change in operating assets and liabilities | (14,047 | ) | 110,634 | |||||||
|
Cash flow from operations before changes in operating assets and |
$ | 191,814 | $ | 198,208 | ||||||
We have included the cash flow from operations before changes in
operating assets and liabilities because:
-
It is an accepted financial indicator used by our management and
companies in our industry to measure the company’s ability to generate
cash which is used to internally fund our business activities. -
It is used by investors and financial analysts to evaluate the
performance of our company.
| Unit Corporation | |||||||||||||||
| Reconciliation of Average Daily Operating Margin Before Elimination of Rig Profit |
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| Three Months Ended | Six Months Ended | ||||||||||||||
| June 30, | June 30, | ||||||||||||||
| 2010 | 2009 | 2010 | 2009 | ||||||||||||
| (In thousands) | |||||||||||||||
| Contract drilling revenue | $ | 72,061 | $ | 49,883 | $ | 132,915 | $ | 138,582 | |||||||
| Contract drilling operating cost | 46,541 | 29,779 | 87,441 | 80,109 | |||||||||||
| Operating profit from contract drilling | 25,520 | 20,104 | 45,474 | 58,473 | |||||||||||
|
Add: |
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|
Elimination of intercompany rig profit and bad debt expense |
|
1,453 |
|
440 |
|
1,829 |
|
1,065 |
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|
Operating profit from contract drilling before elimination of |
26,973 | 20,544 | 47,303 | 59,538 | |||||||||||
| Contract drilling operating days | 5,288 | 2,878 | 9,873 | 7,626 | |||||||||||
|
Average daily operating margin before elimination of rig profit |
$ | 5,101 | $ | 7,138 | $ | 4,791 | $ | 7,807 | |||||||
We have included the average daily operating margin before elimination
of rig profit because:
-
Our management uses the measurement to evaluate the cash flow
performance or our 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 our company.
Unit Corporation
Chief Financial Officer and Treasurer
David
T. Merrill, 918-493-7700
www.unitcorp.com
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