Unit Corporation (NYSE: UNT) reported net income of $49.8 million, or
$1.04 per diluted share, for the three months ended June 30, 2011. For
the same period in 2010, net income was $32.2 million, or $0.68 per
diluted share. Total revenues for the second quarter of 2011 were $291.5
million (40% contract drilling, 45% oil and natural gas, and 15%
mid-stream), compared to $204.6 million (35% contract drilling, 45% oil
and natural gas, and 18% mid-stream) for the second quarter of 2010.
For the first six months of 2011, Unit reported net income of $90.8
million, or $1.89 per diluted share. For the same period in 2010, net
income was $68.3 million, or $1.43 per diluted share. Total revenues for
the first six months of 2011 were $538.9 million (40% contract drilling,
45% oil and natural gas, and 15% mid-stream), compared to $411.2 million
(32% contract drilling, 46% oil and natural gas, and 19% mid-stream) for
the first six months of 2010.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the second quarter of 2011
was 73.1, an increase of 26% from the second quarter of 2010, and an
increase of 4% from the first quarter of 2011. Per day drilling rig
rates for the second quarter of 2011 averaged $18,861, up 26%, or
$3,946, from the second quarter of 2010, and up 7%, or $1,157 from the
first quarter of 2011. Average per day operating margin for the second
quarter of 2011 was $8,370 (before elimination of intercompany drilling
rig profit of $5.1 million). This compares to $5,101 (before elimination
of intercompany drilling rig profit of $1.5 million) for the second
quarter of 2010, an increase of 64% or $3,269. As compared to the first
quarter of 2011 ($8,077 before elimination of intercompany drilling rig
profit of $5.0 million) second quarter 2011 operating margin increased
4% or $293 – in each case with regard to the elimination of intercompany
drilling rig profit see Non-GAAP Financial Measures below.
For the first six months of 2011, Unit averaged 71.6 drilling rigs
working, up 31% from 54.5 drilling rigs working during the first six
months of 2010. Average per day operating margin for the first six
months of 2011 was $8,229 (before elimination of intercompany drilling
rig profit of $10.1 million) as compared to $4,791 (before elimination
of intercompany drilling rig profit of $1.8 million) for the first six
months of 2010, an increase of 72% (in each case with regard to the
elimination of intercompany drilling rig profit see Non-GAAP Financial
Measures below).
The following table illustrates Unit’s drilling rig count at the end of
each period and average utilization rate during the period:
| 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | |||||||||||||||||||
| Rigs | 123 | 122 | 121 | 123 | 123 | 125 | 130 | 130 | 131 | ||||||||||||||||||
| Utilization | 60 | % | 58 | % | 59 | % | 54 | % | 47 | % | 40 | % | 28 | % | 26 | % | 24 | % | |||||||||
Larry Pinkston, Unit’s Chief Executive Officer and President, said:
“During the second quarter, our utilization rate increased and we
obtained an increase in drilling rig day rates over the first quarter of
2011. Our fleet went through a transition in 2010 to accommodate the
growing industry focus on drilling horizontal or directional wells. We
refurbished and upgraded 30 drilling rigs in 2010 in order that they
could undertake this type of drilling. Approximately 81% of our drilling
rigs working today are drilling for oil or natural gas liquids and
approximately 96% are drilling horizontal or directional wells. We have
recently been awarded two additional new build rig contracts. Both
contracts have an initial term of three years and are for 1,500
horsepower diesel-electric drilling rigs. Delivery of these two rigs is
anticipated during the fourth quarter of 2011. We had previously
announced that during 2011 we will add five new 1,500 horsepower
diesel-electric drilling rigs to our fleet. Three of those drilling rigs
are now completed and are working in the Bakken shale. The remaining two
are expected to be completed late in the third quarter. Each of these
five new drilling rigs will initially be working under a two-year
drilling contract. Currently, 80 of our 124 drilling rigs are under
contract. Term contracts (contracts with original terms ranging from six
months to three years in length) are in place for 41 of the 80
contracted drilling rigs. Of these contracts 5 are up for renewal during
the third quarter of 2011, 15 during the fourth quarter of 2011, and 21
after 2011. These contracts do not include the term contracts for the
four new drilling rigs we are currently building and that will be added
to our fleet later this year.”
OIL AND NATURAL GAS SEGMENT INFORMATION
-
Completed 45 and 79 gross wells during the 2011 second quarter and
first six months, respectively. -
39% of second quarter 2011 production was oil and natural gas liquids
compared to 30% for the second quarter of 2010. -
Increased estimated capital expenditures for 2011 from $415 million to
$435 million. - Increased anticipated 2011 production to 11.3 to 11.6 MMBoe.
Second quarter 2011 oil production was 591,000 barrels, in comparison to
321,000 barrels for the same period of 2010, up 84%. Natural gas liquids
(NGLs) production during the second quarter of 2011 was 567,000 barrels,
an increase of 46% when compared to 388,000 barrels for the same period
of 2010. Second quarter 2011 natural gas production increased 13% to
10.9 billion cubic feet (Bcf) compared to 9.7 Bcf for the comparable
quarter of 2010. Second quarter 2011 equivalent production averaged 32.8
MBoe per day, up 28% over the second quarter of 2010 and up 8% over the
first quarter of 2011. Total production for the first six months of 2011
was 5.7 MMBoe.
Unit’s average natural gas price, including the effects of hedges, for
the second quarter of 2011 decreased 23% to $4.30 per thousand cubic
feet (Mcf) as compared to $5.62 per Mcf for the second quarter of 2010.
Unit’s average oil price, including the effects of hedges, for the
second quarter of 2011 was $89.77 per barrel compared to $66.93 per
barrel for the second quarter of 2010, up 34%, and Unit’s average NGLs
price, including the effects of hedges, for the second quarter of 2011
was $45.49 per barrel compared to $33.37 per barrel for the second
quarter of 2010, up 36%. For the first six months of 2011, Unit’s
average natural gas price, including the effects of hedges, decreased
26% to $4.29 per Mcf as compared to $5.79 per Mcf for the first six
months of 2010. Unit’s average oil price, including the effects of
hedges, for the first six months of 2011 was $87.14 per barrel compared
to $67.12 per barrel during the first six months of 2010, a 30%
increase. Unit’s average NGLs price, including the effects of hedges,
for the first six months of 2011 was $42.80 per barrel compared to
$38.01 per barrel during the first six months of 2010, a 13% increase.
Currently for 2011, Unit has hedged 80,000 MMBtu per day of its natural
gas production, 4,000 Bbls per day of its oil production and 504 Bbls
per day of its NGLs production. The natural gas production is hedged
under swap contracts at a comparable average NYMEX price of $4.85. The
average basis differential for the swaps is ($0.19). The oil production
is hedged under swap contracts at an average price of $84.28 per barrel.
The NGLs production is hedged under swap contracts at an average price
of $40.67 per barrel.
For 2012, Unit has to date hedged 45,000 MMBtu per day of its natural
gas production and 4,500 Bbls per day of its oil production. The natural
gas production is hedged under swap contracts at a comparable average
NYMEX price of $5.33. The oil production is hedged under swap contracts
at an average price of $95.91 per barrel.
For 2013, Unit has to date hedged 2,000 Bbls per day of its oil
production. The oil production is hedged under swap contracts at an
average price of $102.05 per barrel.
The following table illustrates certain results for the periods
indicated:
| 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | |||||||||||||||||||
| Oil and NGL Production, MBo |
1,158.6 |
1,034.0 |
925.5 |
756.5 |
708.6 |
679.4 |
641.0 |
658.2 |
738.7 |
||||||||||||||||||
| Natural Gas Production, Bcf |
10.9 |
10.2 |
10.6 |
10.4 |
9.7 |
10.0 |
10.5 |
10.7 |
11.0 |
||||||||||||||||||
| Production, MBoe |
2,983 |
2,739 |
2,698 |
2,478 |
2,325 |
2,352 |
2,389 |
2,444 |
2,572 |
||||||||||||||||||
| Production, MBoe/day |
32.8 |
30.4 |
29.3 |
27.0 |
25.6 |
26.1 |
26.0 |
26.6 |
28.3 |
||||||||||||||||||
|
Realized price,
Boe (1) |
$ |
42.23 |
$ |
40.00 |
$ |
41.58 |
$ |
38.16 |
$ |
38.22 |
$ |
40.92 |
$ |
36.72 |
$ |
35.52 |
$ |
34.50 |
|||||||||
|
(1) Realized price includes oil, natural gas liquids, natural gas |
|||||||||||||||||||||||||||
In the Marmaton horizontal oil play located in Beaver County, Oklahoma,
for the first half 2011, Unit had first sales on a total of 18 wells
with an overall 30-day average rate of 208 Boe per day and an average
working interest of approximately 91%. The average ultimate recovery for
a Marmaton well is estimated at 130 MBoe comprised of 76% oil, 14% NGLs
and 10% natural gas, with an average cost per well of $2.7 million. Unit
has two rigs drilling in the Marmaton which should result in completing
approximately 36 gross wells during the year at a total net cost of $60
million. Unit currently has leases on approximately 70,000 net acres in
the play.
In the Granite Wash (GW) play located in the Texas Panhandle, Unit had
first sales on four horizontal wells during the second quarter. Unit’s
average working interest in these wells is 64%. Of the four new wells,
one well was completed in the GW “A”, two in the GW “B” and one in the
GW “C” zone. The average 30-day rate of production for these four wells
was 6.0 MMcfe per day. For the first half of 2011, Unit had first sales
on nine new GW horizontal wells with an average 30-day production rate
of 6.2 MMcfe per day. The average ultimate recovery for a GW horizontal
well is estimated at 4.3 Bcfe comprised of 8% oil, 39% NGLs and 53%
natural gas with an average cost per well of $5.4 million. Unit plans to
work three to four Unit rigs drilling Granite Wash horizontal wells in
2011 which should result in completing approximately 20 operated GW
wells during the year with a projected total net cost of $85 million.
On July 20, 2011, Unit acquired certain producing properties from an
unaffiliated seller for approximately $12.3 million in cash, subject to
post-closing adjustments, consisting of 30 operated wells and 59
non-operated well interests located in Beaver, Harper and Ellis Counties
in Oklahoma and Lipscomb County, Texas. The purchase price allocation
was $8.4 million for proved properties and $3.9 million for acreage. The
net proved developed reserves associated with the acquisition are
estimated at 6.6 Bcfe (91% natural gas) with production of 1.7 MMcfe per
day. The acquisition also included in excess of 12,000 net held by
production acres in the area for future development.
On July 28, 2011, Unit entered into a purchase and sale agreement with
an unaffiliated seller to acquire certain producing properties for $30.5
million in cash, subject to closing adjustments. The acquisition
consists of more than 500 wells located principally in the Oklahoma
Arkoma Woodford and Hartshorne Coal plays along with other properties
located throughout Oklahoma and Texas. Unit’s preliminary proved
reserves associated with the acquisition are approximately 31.2 Bcfe
(99% natural gas), 83% of which is proved developed, with current
production of approximately 7.8 MMcfe per day. The acquisition also
includes approximately 55,000 net acres of which 96% is held by
production. Closing of this acquisition, subject to customary due
diligence, is expected to occur before the end of the third quarter.
Pinkston said: “We are pleased with the second quarter results from our
drilling activity. This quarter marks the fourth consecutive quarter
that production has increased. Our strategy of focusing on oil or NGLs
rich prospects is evident in our second quarter 2011 production results
of which 39% was oil and NGLs as compared to 30% in the second quarter
of 2010 and 38% in the first quarter of 2011. For the second quarter, we
completed 45 gross wells with a success rate of 93% compared to 39 gross
wells with a 92% success rate during the second quarter of 2010. We are
increasing our estimated capital expenditures for 2011 from $415 million
to $435 million with the increase primarily being associated with
acquiring acreage both within our existing core plays and in areas
outside of our core plays. For the year, we continue to plan to drill
180 gross wells; however, we are increasing our anticipated annual
production guidance to 11.3 to 11.6 MMBoe from our previous guidance of
11.0 to 11.3 MMBoe, due primarily to favorable results associated with
our activity during the first half of 2011.”
MID-STREAM SEGMENT INFORMATION
-
Increased second quarter 2011 liquids sold per day volumes, processing
volumes per day, and gathering volumes per day by 27%, 10% and 4%,
respectively, over the second quarter of 2010. -
Construction of 16-mile pipeline and related compressor station in
Preston County, West Virginia is on schedule to be operational during
the third quarter of 2011. -
Began construction activities for a gathering system and a compressor
station in Tioga and Potter Counties, Pennsylvania. -
Signed a letter of intent to construct a 7-mile, 16″ pipeline in
Allegheny and Butler Counties, Pennsylvania. -
Increased estimated capital expenditures for 2011 from $47 million to
$86 million.
Second quarter of 2011 per day processing volumes were 90,737 MMBtu
while liquids sold volumes were 356,484 gallons per day, an increase of
10% and 27%, respectively, over the second quarter of 2010. Second
quarter 2011 per day gathering volumes was 190,921 MMBtu, up 4% over the
second quarter of 2010. Operating profit (as defined in the Selected
Financial and Operational Highlights) for the second quarter was $7.6
million, an increase of $0.2 million from the second quarter of 2010 as
increased revenue was offset by increased cost for gas purchased. As
compared to the first quarter of 2011 operating profit decreased $3.1
million primarily due to the renegotiated contracts (effective April 1,
2011) with producers supplying gas to one of our processing plants that
we had previously discussed during the first quarter.
For the first six months of 2011, processing volumes of 88,603 MMBtu per
day and liquids sold volumes of 342,486 gallons per day increased 11%
and 28%, respectively, from the first six months of 2010. Gathering
volumes for the first six months of 2011 were 188,340 MMBtu per day, a
3% increase from the first six months of 2010.
The following table illustrates certain results from this segment’s
operations for the periods indicated:
| 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | ||||||||||
|
Gas gathered MMBtu/day |
190,921 |
185,730 |
188,252 |
183,161 |
183,858 |
180,117 |
177,145 |
179,047 |
187,666 |
|||||||||
|
Gas processed MMBtu/day |
90,737 |
86,445 |
85,195 |
84,175 |
82,699 |
76,513 |
77,501 |
77,923 |
75,481 |
|||||||||
|
Liquids sold Gallons/day |
356,484 |
328,333 |
291,186 |
260,519 |
279,736 |
253,707 |
263,668 |
251,830 |
239,121 |
|||||||||
Pinkston said: “Processing and liquids sold volumes continue to increase
and gas gathered volumes remain strong. In our Mid-continent operations,
we are in the process of installing a high-efficiency processing plant
at our Cashion system, located in Logan, Canadian, Oklahoma and
Kingfisher Counties in Oklahoma, which will improve liquids recovery
capability compared to our existing plant which it is replacing. In
Grant County, Oklahoma, we have begun construction of a new gathering
system, which will include a processing plant, and is anticipated to be
completed during the third quarter of 2011. In connection with our
Appalachian operations, we are in the final stages of constructing a
16-mile, 16″ pipeline and a compressor station in Preston County,
West Virginia, which will have a capacity of approximately 220.0 MMcf
per day. We anticipate this pipeline will be operational during the
third quarter of 2011. In addition to the Preston County pipeline, we
began construction activities for a gathering system and a compressor
station in Tioga and Potter Counties, Pennsylvania. This system will
deliver gas to Dominion Transmission pipeline and is scheduled to be
completed in the fourth quarter of this year or first quarter of 2012.
We recently signed a letter of intent with a third party to construct a
pipeline in Allegheny and Butler Counties of Pennsylvania. Land and
survey work associated with the first phase, which consists of a 7-mile,
16″ pipeline, has begun and construction is anticipated to be completed
during the first half of 2012.”
FINANCIAL INFORMATION
Unit ended the second quarter of 2011 with working capital of $43.7
million, long-term debt of $250.0 million, and a debt to capitalization
ratio of 12%. In May 2011, Unit completed an underwritten public
offering of $250 million aggregate principal amount of senior
subordinated notes due 2021, which bears interest at a rate of 6.625
percent per year. The notes were sold at 100 percent of par and Unit
used the net proceeds primarily to repay its then outstanding borrowings
under its credit facility. As of June 30, 2011, the company had no
borrowings outstanding under its credit facility. The amount of the
credit facility 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 (currently
$532.5 million), but in either event, not to exceed the maximum credit
facility amount of $400 million. We are in the process of renegotiating
our credit facility to extend the maturity date past May 2012.
MANAGEMENT COMMENT
Larry Pinkston said: “We are pleased with the operating results of the
second quarter and first half of 2011. For the remainder of the year, we
will continue to focus our exploration efforts on our oil and natural
gas liquids rich plays such as the Granite Wash and Marmaton and our
contract drilling operations will continue responding to the demand for
horizontal drilling by our customers by refurbishing and upgrading our
existing rigs and, where appropriate, adding new drilling rigs to our
fleet. Our mid-stream segment is always exploring for additional
opportunities to grow its operations as is evident by the new projects
in the Mid-continent and Appalachia areas. We are optimistic about the
remainder of 2011 and we are well positioned, especially given the
recent financing arrangements we have completed, to take advantage of
growth opportunities that may arise in all three of our business
segments.”
WEBCAST
Unit will webcast its second quarter earnings conference call live over
the Internet on August 2, 2011 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 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.
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, 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, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| Statement of Operations: | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Contract drilling | $ | 115,183 | $ | 72,061 | $ | 213,171 | $ | 132,915 | ||||||||
| Oil and natural gas | 131,662 | 91,136 | 241,496 | 190,189 | ||||||||||||
| Gas gathering and processing | 44,368 | 36,344 | 84,132 | 77,479 | ||||||||||||
| Other, net | 282 | 5,062 | 101 | 10,570 | ||||||||||||
| Total revenues | 291,495 | 204,603 | 538,900 | 411,153 | ||||||||||||
| Expenses: | ||||||||||||||||
| Contract drilling: | ||||||||||||||||
| Operating costs | 64,238 | 46,541 | 117,082 | 87,441 | ||||||||||||
| Depreciation | 19,218 | 16,445 | 36,515 | 30,231 | ||||||||||||
| Oil and natural gas: | ||||||||||||||||
| Operating costs | 33,417 | 23,817 | 64,198 | 48,851 | ||||||||||||
|
Depreciation, depletion and amortization |
44,550 | 26,319 | 84,818 | 51,655 | ||||||||||||
| Gas gathering and processing: | ||||||||||||||||
| Operating costs | 36,789 | 28,938 | 65,844 | 61,664 | ||||||||||||
|
Depreciation and amortization |
3,837 | 3,982 | 7,610 | 7,923 | ||||||||||||
| General and administrative | 7,496 | 6,456 | 14,388 | 12,735 | ||||||||||||
| Interest, net | 673 | — | 727 | — | ||||||||||||
| Total expenses | 210,218 | 152,498 | 391,182 | 300,500 | ||||||||||||
| Income Before Income Taxes | 81,277 | 52,105 | 147,718 | 110,653 | ||||||||||||
| Income Tax Expense: | ||||||||||||||||
| Current | — | 3,825 | — | 6,065 | ||||||||||||
| Deferred | 31,458 | 16,105 | 56,872 | 36,260 | ||||||||||||
| Total income taxes | 31,458 | 19,930 | 56,872 | 42,325 | ||||||||||||
| Net Income | $ | 49,819 | $ | 32,175 | $ | 90,846 | $ | 68,328 | ||||||||
| Net Income per Common Share: | ||||||||||||||||
| Basic | $ | 1.05 | $ | 0.68 | $ | 1.91 | $ | 1.45 | ||||||||
| Diluted | $ | 1.04 | $ | 0.68 | $ | 1.89 | $ | 1.43 | ||||||||
|
Weighted Average Common Shares Outstanding: |
||||||||||||||||
| Basic | 47,655 | 47,171 | 47,620 | 47,146 | ||||||||||||
| Diluted | 47,983 | 47,656 | 47,944 | 47,671 | ||||||||||||
| June 30, | December 31, | ||||||||
| 2011 | 2010 | ||||||||
| Balance Sheet Data: | |||||||||
| Current assets | $ | 189,831 | $ | 188,180 | |||||
| Total assets | $ | 2,917,502 | $ | 2,669,240 | |||||
| Current liabilities | $ | 146,133 | $ | 147,128 | |||||
| Long-term debt | $ | 250,000 | $ | 163,000 | |||||
| Other long-term liabilities | $ | 94,635 | $ | 92,389 | |||||
| Deferred income taxes | $ | 613,476 | $ | 556,106 | |||||
| Shareholders’ equity | $ | 1,813,258 | $ | 1,710,617 | |||||
| Six Months Ended June 30, | |||||||||
| 2011 | 2010 | ||||||||
| Statement of Cash Flows Data: | |||||||||
|
Cash Flow From Operations before Changes in Operating Assets and |
$ | 284,726 | $ | 191,814 | |||||
| Net Change in Operating Assets and Liabilities | (25,216 | ) | (14,047 | ) | |||||
| Net Cash Provided by Operating Activities | $ | 259,510 | $ | 177,767 | |||||
| Net Cash Used in Investing Activities | $ | (351,942 | ) | $ | (277,265 | ) | |||
|
Net Cash Provided by Financing Activities |
$ |
92,296 |
$ |
100,119 | |||||
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| Contract Drilling Operations Data: | ||||||||||||||||
| Rigs Utilized | 73.1 | 58.1 | 71.6 | 54.5 | ||||||||||||
| Operating Margins (2) | 44 | % | 35 | % | 45 | % | 34 | % | ||||||||
| Operating Profit Before Depreciation (2) ($MM) | $ | 50.9 | $ | 25.5 | $ | 96.1 | $ | 45.5 | ||||||||
| Oil and Natural Gas Operations Data: | ||||||||||||||||
| Production: | ||||||||||||||||
| Oil – MBbls | 591 | 321 | 1,147 | 623 | ||||||||||||
| Natural Gas Liquids – MBbls | 567 | 388 | 1,046 | 765 | ||||||||||||
| Natural Gas – MMcf | 10,946 | 9,701 | 21,178 | 19,735 | ||||||||||||
| Average Prices: | ||||||||||||||||
| Oil price per barrel received | $ | 89.77 | $ | 66.93 | $ | 87.14 | $ | 67.12 | ||||||||
| Oil price per barrel received, excluding hedges | $ | 101.02 | $ | 74.49 | $ | 96.06 | $ | 75.08 | ||||||||
| NGLs price per barrel received | $ | 45.49 | $ | 33.37 | $ | 42.80 | $ | 38.01 | ||||||||
|
NGLs price per barrel received, excluding hedges |
$ | 46.58 | $ | 33.10 | $ | 43.72 | $ | 37.88 | ||||||||
| Natural Gas price per Mcf received | $ | 4.30 | $ | 5.62 | $ | 4.29 | $ | 5.79 | ||||||||
|
Natural Gas price per Mcf received, excluding hedges |
$ | 3.97 | $ | 3.72 | $ | 3.91 | $ | 4.44 | ||||||||
| Operating Profit Before DD&A (2) ($MM) | $ | 98.2 | $ | 67.3 | $ | 177.3 | $ | 141.3 | ||||||||
| Mid-Stream Operations Data: | ||||||||||||||||
| Gas Gathering – MMBtu/day | 190,921 | 183,858 | 188,340 | 181,998 | ||||||||||||
| Gas Processing – MMBtu/day | 90,737 | 82,699 | 88,603 | 79,623 | ||||||||||||
| Liquids Sold – Gallons/day | 356,484 | 279,736 | 342,486 | 266,793 | ||||||||||||
|
Operating Profit Before Depreciation and Amortization (2) ($MM) |
$ | 7.6 | $ | 7.4 | $ | 18.3 | $ | 15.8 | ||||||||
|
(1) The company considers its cash flow from operations before |
||||||||||||||||
|
(2) Operating profit before depreciation is calculated by taking |
||||||||||||||||
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 cash flow from operations before changes in
operating assets and liabilities and our drilling segment’s average
daily operating margin before elimination of intercompany 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, 2011 and
2010. Non-GAAP financial measures should not be considered by themselves
or a substitute for our results reported in accordance with GAAP.
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Unit Corporation |
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Reconciliation of Cash Flow From Operations Before Changes in |
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| Six Months Ended
June 30, |
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| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
| Net cash provided by operating activities | $ | 259,510 | $ | 177,767 | ||||
| Subtract: | ||||||||
| Net change in operating assets and liabilities | (25,216 | ) | (14,047 | ) | ||||
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Cash flow from operations before changes in operating assets and |
$ | 284,726 | $ | 191,814 | ||||
________________
We have included the cash flow from operations before changes in
operating assets and liabilities because:
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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.
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Unit Corporation |
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Reconciliation of Average Daily Operating Margin Before |
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| Three Months Ended | Six Months Ended | ||||||||||||||
| March 31, | June 30, | June 30, | |||||||||||||
| 2011 | 2011 | 2010 | 2011 | 2010 | |||||||||||
| (In thousands) | |||||||||||||||
| Contract drilling revenue | $ | 97,988 | $ | 115,183 | $ | 72,061 | $ | 213,171 | $ | 132,915 | |||||
| Contract drilling operating cost | 52,844 | 64,238 | 46,541 | 117,082 | 87,441 | ||||||||||
| Operating profit from contract drilling | 45,144 | 50,945 | 25,520 | 96,089 | 45,474 | ||||||||||
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Add:
Elimination of intercompany rig profit |
5,044 |
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5,092 |
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1,453 |
10,136 |
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1,829 |
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Operating profit from contract drilling before elimination of |
50,188 | 56,037 | 26,973 | 106,225 | 47,303 | ||||||||||
| Contract drilling operating days | 6,214 | 6,695 | 5,288 | 12,909 | 9,873 | ||||||||||
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Average daily operating margin before elimination of intercompany |
$ | 8,077 | $ | 8,370 | $ | 5,101 | $ | 8,229 | $ | 4,791 | |||||
________________
We have included the average daily operating margin before elimination
of intercompany rig profit because:
-
Our management uses the measurement to evaluate the cash flow
performance of 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
David T. Merrill
Chief Financial Officer and
Treasurer
918-493-7700
www.unitcorp.com
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