Unit Corporation (NYSE: UNT) reported net income of $53.4 million, or
$1.11 per diluted share, for the three months ended September 30, 2011.
For the same period in 2010, net income was $34.5 million, or $0.73 per
diluted share. Total revenues for the third quarter of 2011 were $323.8
million (39% contract drilling, 42% oil and natural gas, and 19%
mid-stream), compared to $218.1 million (39% contract drilling, 44% oil
and natural gas, and 17% mid-stream) for the third quarter of 2010.
For the first nine months of 2011, Unit reported net income of $144.2
million, or $3.01 per diluted share. For the same period in 2010, net
income was $102.8 million, or $2.17 per diluted share. Total revenues
for the first nine months of 2011 were $862.7 million (39% contract
drilling, 44% oil and natural gas, and 17% mid-stream), compared to
$629.3 million (35% contract drilling, 46% oil and natural gas, and 18%
mid-stream) for the first nine months of 2010.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the third quarter of 2011
was 78.9, an increase of 21% from the third quarter of 2010, and an
increase of 8% from the second quarter of 2011. Per day drilling rig
rates for the third quarter of 2011 averaged $19,309, up 22%, or $3,495,
from the third quarter of 2010, and up 2%, or $448 from the second
quarter of 2011. Average per day operating margin for the third quarter
of 2011 was $8,413 (before elimination of intercompany drilling rig
profit of $4.8 million). This compares to $7,056 (before elimination of
intercompany drilling rig profit of $2.9 million) for the third quarter
of 2010, an increase of 19% or $1,357. As compared to the second quarter
of 2011 ($8,370 before elimination of intercompany drilling rig profit
of $5.1 million) third quarter 2011 operating margin increased 1% (in
each case with regard to the elimination of intercompany drilling rig
profit see Non-GAAP Financial Measures below).
For the first nine months of 2011, Unit averaged 74.0 drilling rigs
working, up 27% from 58.2 drilling rigs working during the first nine
months of 2010. Average per day operating margin for the first nine
months of 2011 was $8,295 (before elimination of intercompany drilling
rig profit of $15.0 million) as compared to $5,649 (before elimination
of intercompany drilling rig profit of $4.7 million) for the first nine
months of 2010, an increase of 47% (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:
| 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | ||||||||||
| Rigs | 126 | 123 | 122 | 121 | 123 | 123 | 125 | 130 | 130 | |||||||||
| Utilization | 63% | 60% | 58% | 59% | 54% | 47% | 40% | 28% | 26% | |||||||||
Larry Pinkston, Unit’s Chief Executive Officer and President, said:
“During the third quarter, both our utilization rate and drilling day
rates increased over those for the second quarter of 2011. Approximately
79% of our drilling rigs working today are drilling for oil or natural
gas liquids and approximately 95% are drilling horizontal or directional
wells. During the third quarter of 2011 we were awarded two additional
new build drilling rig contracts. Both contracts have an initial term of
three years and are for 1,500 horsepower diesel-electric drilling rigs.
Delivery of these rigs is anticipated during the fourth quarter of 2011.
On completion of these two new drilling rigs, we will have 128 drilling
rigs in our fleet. Currently, 82 of our 126 drilling rigs are under
contract. Term contracts (contracts with original terms ranging from six
months to three years in length) are in place for 59 of the 82
contracted drilling rigs. Of these contracts, nine are up for renewal in
the fourth quarter of 2011, 38 during 2012, and 12 during 2013. The two
contracts for the two new drilling rigs we are building are not
reflected in the term contracts reported above.”
OIL AND NATURAL GAS SEGMENT INFORMATION
-
Completed 40 and 119 gross wells during the third quarter and first
nine months of 2011, respectively. -
38% of third quarter 2011 production was oil and natural gas liquids
compared to 30% for the third quarter of 2010. -
Increased our anticipated 2011 production to now fall within the range
of 11.8 to 12.1 MMBoe.
Third quarter 2011 oil production was 620,000 barrels, as compared to
379,000 barrels for the same period of 2010, an increase of 64%. Natural
gas liquids (NGLs) production during the third quarter of 2011 was
578,000 barrels, an increase of 53% when compared to 378,000 barrels for
the same period of 2010. Third quarter 2011 natural gas production
increased 11% to 11.6 billion cubic feet (Bcf) compared to 10.4 Bcf for
the comparable quarter of 2010. Third quarter 2011 equivalent production
averaged 33.9 MBoe per day, up 26% over the third quarter of 2010 and up
4% over the second quarter of 2011. Total production for the first nine
months of 2011 was 8.8 MMBoe.
Unit’s average natural gas price, including the effects of hedges, for
the third quarter of 2011 decreased 21% to $4.39 per thousand cubic feet
(Mcf) as compared to $5.55 per Mcf for the third quarter of 2010. Unit’s
average oil price, including the effects of hedges, for the third
quarter of 2011 was $86.19 per barrel compared to $66.94 per barrel for
the third quarter of 2010, up 29%, and Unit’s average NGLs price,
including the effects of hedges, for the third quarter of 2011 was
$45.40 per barrel compared to $31.67 per barrel for the third quarter of
2010, up 43%. For the first nine months of 2011, Unit’s average natural
gas price, including the effects of hedges, decreased 24% to $4.33 per
Mcf as compared to $5.71 per Mcf for the first nine months of 2010.
Unit’s average oil price, including the effects of hedges, for the first
nine months of 2011 was $86.80 per barrel compared to $67.05 per barrel
during the first nine months of 2010, a 29% increase. Unit’s average
NGLs price, including the effects of hedges, for the first nine months
of 2011 was $43.72 per barrel compared to $35.91 per barrel during the
first nine months of 2010, a 22% increase.
Currently for the remainder of 2011, Unit has hedged 80,000 MMBtu per
day of its natural gas production, 4,000 Bbls per day of its oil
production and 2,535 Bbls per day of its NGLs production. The natural
gas production is hedged under swap contracts at a comparable average
NYMEX price of $4.70. 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 $43.94 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. For the
first quarter of 2012, Unit hedged 1,988 Bbls per day of its NGLs
production and 683 Bbls per day of its second quarter 2012 NGLs
production. The natural gas production is hedged under swap contracts at
a comparable average NYMEX price of $5.24. The oil production is hedged
under swap contracts at an average price of $95.91 per barrel. The NGLs
production is hedged under swap contracts at an average price of $42.53
per barrel for the first quarter and $44.47 per barrel for the second
quarter.
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:
| 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | ||||||||||
|
Oil and NGL Production, MBo |
1,197.5 |
1,158.6 |
1,034.0 |
925.5 |
756.5 |
708.6 |
679.4 |
641.0 |
658.2 |
|||||||||
|
Natural Gas Production, Bcf |
11.6 |
10.9 |
10.2 |
10.6 |
10.4 |
9.7 |
10.0 |
10.5 |
10.7 |
|||||||||
| Production, MBoe |
3,123 |
2,983 |
2,739 |
2,698 |
2,478 |
2,325 |
2,352 |
2,389 |
2,444 |
|||||||||
| Production, MBoe/day |
33.9 |
32.8 |
30.4 |
29.3 |
27.0 |
25.6 |
26.1 |
26.0 |
26.6 |
|||||||||
|
Realized price,
Boe (1) |
$41.75 |
$42.23 |
$40.00 |
$41.58 |
$38.16 |
$38.22 |
$40.92 |
$36.72 |
$35.52 |
(1) Realized price includes oil, natural gas liquids, natural gas and
associated hedges.
In the Marmaton horizontal oil play located in Beaver County, Oklahoma,
Unit had first sales on a total of 25 wells during the first nine months
of 2011. These wells had an overall 30-day average rate of 242 Boe per
day consisting of 78% oil, 14% NGLs and 8% natural gas. Unit owned an
average working interest of approximately 81% in the wells. The average
ultimate recovery for a Marmaton well is estimated at 130 MBoe with an
average cost per well of $2.7 million. Unit has two drilling rigs
operating in the Marmaton and expects to complete a total of 34 gross
wells during the year with an approximate net cost of $70 million. Unit
currently has leases on approximately 84,000 net acres in the play.
In the Granite Wash (GW) play located in the Texas Panhandle, Unit had
first sales on five horizontal wells during the third quarter. Unit’s
average working interest in these wells is 79%. Of the five new wells,
one well was completed in the GW “A”, three in the GW “B”, and one in
the GW “C1” zone. The average 30-day rate for these five wells was 7.2
MMcfe per day. For the first nine months of 2011, Unit had first sales
on a total of 14 new GW horizontal wells with an average 30-day
production rate of 6.5 MMcfe per day consisting of 15% oil, 36% NGLs and
49% natural gas. The average ultimate recovery for a GW horizontal well
is estimated at 4.1 Bcfe with an average cost per well of $5.5 million.
Unit anticipates operating three to four Unit drilling rigs in the
Granite Wash during the remainder of 2011, which should result in a
total of 19 operated GW wells during the year at a projected net cost of
$85 million.
On August 31, 2011, Unit acquired certain producing oil and gas
properties for $30.5 million in cash, subject to closing adjustments,
from an unaffiliated seller. Included in the acquisition were more than
500 wells located principally in the Oklahoma Arkoma Woodford and
Hartshorne Coal plays along with other properties located throughout
Oklahoma and Texas. The proved reserves associated with the acquisition
are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved
developed. The acquisition also included approximately 55,000 net acres
of which 96% is held by production.
Pinkston said: “We are pleased with the third quarter results from our
exploration operations. This quarter marks the fifth consecutive quarter
that production has increased. Our strategy of drilling oil or NGLs rich
wells is evident in our third quarter 2011 production results. Total
liquids (oil and NGLs) production increased 58% between the third
quarter of 2011 and the third quarter of 2010. For the year, we plan to
drill 160 gross wells. We are also increasing our anticipated annual
production guidance to a range between 11.8 to 12.1 MMBoe from our
previous guidance of 11.3 to 11.6 MMBoe.”
MID-STREAM SEGMENT INFORMATION
-
Increased third quarter 2011 liquids sold per day volumes, processing
volumes per day, and gathering volumes per day by 73%, 54% and 25%,
respectively, over the third quarter of 2010. -
Construction of 16-mile pipeline and related compressor station in
Preston County, West Virginia is scheduled to be complete and the
pipeline operational during the fourth quarter of 2011. -
Signed a letter of intent to construct a 7-mile, 16″ pipeline in
Allegheny and Butler Counties, Pennsylvania scheduled for completion
during the fourth quarter of 2011.
Third quarter of 2011 per day processing volumes were 129,820 MMBtu
while liquids sold volumes were 449,604 gallons per day, an increase of
54% and 73%, respectively, over the third quarter of 2010. Third quarter
2011 per day gathering volumes were 228,247 MMBtu, up 25% over the third
quarter of 2010. Operating profit (as defined in the Selected Financial
and Operational Highlights) for the third quarter was $7.4 million, an
increase of 11% from the third quarter of 2010, primarily due to
increases in volumes gathered, processed and liquids sold, partially
offset by increased cost for gas purchased. Compared to the second
quarter of 2011, operating profit decreased 3% primarily because of the
lower amounts we now receive under certain contracts that we were
required to renegotiate during the first quarter when the original term
of those contracts expired.
For the first nine months of 2011, processing volumes of 102,493 MMBtu
per day and liquids sold volumes of 378,585 gallons per day increased
26% and 43%, respectively, from the first nine months of 2010. Gathering
volumes for the first nine months of 2011 were 201,788 MMBtu per day, an
11% increase from the first nine months of 2010.
The following table illustrates certain results from this segment’s
operations for the periods indicated:
| 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | 4th Qtr 09 | 3rd Qtr 09 | ||||||||||
|
Gas gathered MMBtu/day |
228,247 |
190,921 |
185,730 |
188,252 |
183,161 |
183,858 |
180,117 |
177,145 |
179,047 |
|||||||||
|
Gas processed MMBtu/day |
129,820 |
90,737 |
86,445 |
85,195 |
84,175 |
82,699 |
76,513 |
77,501 |
77,923 |
|||||||||
|
Liquids sold
Gallons/day |
449,604 |
356,484 |
328,333 |
291,186 |
260,519 |
279,736 |
253,707 |
263,668 |
251,830 |
|||||||||
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 replacing the existing plant on our Cashion
system with a high-efficiency gas processing plant. The new plant is
expected to be operational during the first quarter of 2012. It will
increase our processing capacity and will improve our liquids recovery
capability by 12 to 15%. The Cashion plant gathers gas across Logan,
Canadian, Oklahoma and Kingfisher Counties in Oklahoma. In the
Mississippi Lime play in Grant County, Oklahoma, our new gathering
system and processing plant became operational in October. One well is
online and three more wells are in the process of being connected. We
anticipate an additional 25 to 30 wells to be connected during 2012 due
to active drilling by multiple producers in the area around the plant.
This is our entrance into the Mississippi Lime play. In our Appalachian
operations, we are in the final stages of completing 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.
Currently, we have four wells connected with an expected total initial
flow volume in the 8 to 10 MMcf per day range. Three additional wells
have been drilled and are waiting on completion prior to being
connected. We anticipate this pipeline will be operational during the
fourth quarter of 2011. In addition to the Preston County pipeline, we
recently signed a letter of intent with a third party to construct a
pipeline in Allegheny and Butler Counties of Pennsylvania. First flow of
gas from this new system is expected to occur in the fourth quarter of
2011. Expectations are that the first well will flow up to 10 MMcf per
day, and we anticipate four more wells to be drilled and connected
during the first half of 2012.”
FINANCIAL INFORMATION
Unit ended the third quarter of 2011 with working capital of $57.9
million, long-term debt of $305.4 million ($250 million of senior
subordinated notes and $55.4 million of senior credit facility), and a
debt to capitalization ratio of 14%. On September 13, 2011, Unit entered
into a new five year unsecured senior credit facility. Under the credit
facility, the amount available for Unit to borrow is the lesser of the
amount Unit elects as the commitment amount (currently $250 million) or
the value of the borrowing base as determined by the lenders (currently
$600 million), but in either event not to exceed the maximum credit
facility amount of $750 million. As of September 30, 2011, Unit had
$55.4 million in borrowings outstanding under its credit facility.
MANAGEMENT COMMENT
Pinkston said: “We are pleased with the operating results of the third
quarter and first nine months of 2011. For the remainder of the year, we
will continue to focus our exploration efforts on our oil and natural
gas liquids rich prospects like the Granite Wash and Marmaton
formations. Our contract drilling operations will continue responding to
our customers’ demands for horizontal drilling by continuing to
refurbish and upgrade our existing drilling rigs and, where appropriate,
adding new drilling rigs to our fleet. Our midstream segment continues
to grow its operations as evidenced 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 arise in all three of our business segments.”
WEBCAST
Unit will webcast its third quarter earnings conference call live over
the Internet on November 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 | Nine Months Ended | |||||||||||||||||||
| September 30, | September 30, | |||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||
| Statement of Operations: | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Contract drilling | $ | 128,927 | $ | 85,004 | $ | 342,098 | $ | 217,919 | ||||||||||||
| Oil and natural gas | 134,897 | 96,562 | 376,393 | 286,751 | ||||||||||||||||
| Gas gathering and processing | 60,688 | 37,429 | 144,820 | 114,908 | ||||||||||||||||
| Other, net | (667 | ) | (879 | ) | (566 | ) | 9,691 | |||||||||||||
| Total revenues | 323,845 | 218,116 | 862,745 | 629,269 | ||||||||||||||||
| Expenses: | ||||||||||||||||||||
| Contract drilling: | ||||||||||||||||||||
| Operating costs | 73,004 | 45,406 | 190,086 | 132,847 | ||||||||||||||||
| Depreciation | 20,818 | 18,469 | 57,333 | 48,700 | ||||||||||||||||
| Oil and natural gas: | ||||||||||||||||||||
| Operating costs | 29,598 | 27,092 | 93,796 | 75,943 | ||||||||||||||||
| Depreciation, depletion | ||||||||||||||||||||
| and amortization | 47,195 | 30,091 | 132,013 | 81,746 | ||||||||||||||||
| Gas gathering and processing: | ||||||||||||||||||||
| Operating costs | 53,299 | 30,743 | 119,143 | 92,407 | ||||||||||||||||
| Depreciation | ||||||||||||||||||||
| and amortization | 4,017 | 3,823 | 11,627 | 11,746 | ||||||||||||||||
| General and administrative | 7,800 | 6,637 | 22,188 | 19,372 | ||||||||||||||||
| Interest, net | 1,351 | — | 2,078 | — | ||||||||||||||||
| Total expenses | 237,082 | 162,261 | 628,264 | 462,761 | ||||||||||||||||
| Income Before Income Taxes | 86,763 | 55,855 | 234,481 | 166,508 | ||||||||||||||||
| Income Tax Expense: | ||||||||||||||||||||
| Current | (3,949 | ) | (8,553 | ) | (3,949 | ) | (2,488 | ) | ||||||||||||
| Deferred | 37,352 | 29,917 | 94,224 | 66,177 | ||||||||||||||||
| Total income taxes | 33,403 | 21,364 | 90,275 | 63,689 | ||||||||||||||||
| Net Income | $ | 53,360 | $ | 34,491 | $ | 144,206 | $ | 102,819 | ||||||||||||
| Net Income per Common Share: | ||||||||||||||||||||
| Basic | $ | 1.12 | $ | 0.73 | $ | 3.03 | $ | 2.18 | ||||||||||||
| Diluted | $ | 1.11 | $ | 0.73 | $ | 3.01 | $ | 2.17 | ||||||||||||
| Weighted Average Common | ||||||||||||||||||||
| Shares Outstanding: | ||||||||||||||||||||
| Basic | 47,687 | 47,358 | 47,642 | 47,217 | ||||||||||||||||
| Diluted | 47,968 | 47,495 | 47,932 | 47,384 | ||||||||||||||||
| September 30, | December 31, | ||||||||
| 2011 | 2010 | ||||||||
| Balance Sheet Data: | |||||||||
| Current assets | $ | 235,970 | $ | 188,180 | |||||
| Total assets | $ | 3,165,251 | $ | 2,669,240 | |||||
| Current liabilities | $ | 178,056 | $ | 147,128 | |||||
| Long-term debt | $ | 305,400 | $ | 163,000 | |||||
| Other long-term liabilities | $ | 112,701 | $ | 92,389 | |||||
| Deferred income taxes | $ | 658,659 | $ | 556,106 | |||||
| Shareholders’ equity | $ | 1,910,435 | $ | 1,710,617 | |||||
| Nine Months Ended September 30, | |||||||||
| 2011 | 2010 | ||||||||
| Statement of Cash Flows Data: | |||||||||
| Cash Flow From Operations before Changes | |||||||||
| in Operating Assets and Liabilities (1) | $ | 450,725 | $ | 309,861 | |||||
| Net Change in Operating Assets and Liabilities | (32,874 | ) | (25,965 | ) | |||||
| Net Cash Provided by Operating Activities | $ | 417,851 | $ | 283,896 | |||||
| Net Cash Used in Investing Activities | $ | (583,790 | ) | $ | (393,804 | ) | |||
|
Net Cash Provided by Financing Activities |
$ |
165,740 |
$ |
109,901 | |||||
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| Contract Drilling Operations Data: | ||||||||||||||||
| Rigs Utilized | 78.9 | 65.4 | 74.0 | 58.2 | ||||||||||||
| Operating Margins (2) | 43% | 47% | 44% | 39% | ||||||||||||
| Operating Profit Before Depreciation (2) ($MM) | $ | 55.9 | $ | 39.6 | $ | 152.0 | $ | 85.1 | ||||||||
| Oil and Natural Gas Operations Data: | ||||||||||||||||
| Production: | ||||||||||||||||
| Oil – MBbls | 620 | 379 | 1,767 | 1,002 | ||||||||||||
| Natural Gas Liquids – MBbls | 578 | 378 | 1,623 | 1,143 | ||||||||||||
| Natural Gas – MMcf | 11,553 | 10,385 | 32,730 | 30,121 | ||||||||||||
| Average Prices: | ||||||||||||||||
| Oil price per barrel received | $ | 86.19 | $ | 66.94 | $ | 86.80 | $ | 67.05 | ||||||||
| Oil price per barrel received, excluding hedges | $ | 89.47 | $ | 72.52 | $ | 93.75 | $ | 74.11 | ||||||||
| NGLs price per barrel received | $ | 45.40 | $ | 31.67 | $ | 43.72 | $ | 35.91 | ||||||||
| NGLs price per barrel received, excluding hedges | $ | 46.33 | $ | 31.27 | $ | 44.65 | $ | 35.70 | ||||||||
| Natural Gas price per Mcf received | $ | 4.39 | $ | 5.55 | $ | 4.33 | $ | 5.71 | ||||||||
|
Natural Gas price per Mcf received, excluding hedges |
$ | 4.01 | $ | 3.94 | $ | 3.94 | $ | 4.27 | ||||||||
| Operating Profit Before DD&A (2) ($MM) | $ | 105.3 | $ | 69.5 | $ | 282.6 | $ | 210.8 | ||||||||
| Mid-Stream Operations Data: | ||||||||||||||||
| Gas Gathering – MMBtu/day | 228,247 | 183,161 | 201,788 | 182,390 | ||||||||||||
| Gas Processing – MMBtu/day | 129,820 | 84,175 | 102,493 | 81,157 | ||||||||||||
| Liquids Sold – Gallons/day | 449,604 | 260,519 | 378,585 | 264,679 | ||||||||||||
|
Operating Profit Before Depreciation and Amortization (2) ($MM) |
$ | 7.4 | $ | 6.7 | $ | 25.7 | $ | 22.5 | ||||||||
________________
(1) The company considers its cash flow from operations before changes
in operating assets and liabilities an important measure in meeting the
performance goals of the company (see Non-GAAP Financial Measures below).
(2) Operating profit before depreciation is calculated by taking
operating revenues by segment less operating expenses excluding
depreciation, depletion, amortization general and administrative and
interest expense. Operating margins are calculated by dividing operating
profit by segment revenue.
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 nine months ended September 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.
Unit Corporation
Reconciliation of Cash Flow From
Operations Before Changes in Operating Assets and Liabilities
| Nine Months Ended
September 30, |
|||||||
| 2011 | 2010 | ||||||
| (In thousands) | |||||||
| Net cash provided by operating activities | $ | 417,851 | $ | 283,896 | |||
| Subtract: | |||||||
| Net change in operating assets and liabilities | 32,874 | 25,965 | |||||
| Cash flow from operations before changes | |||||||
| in operating assets and liabilities | $ | 450,725 | $ | 309,861 | |||
________________
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 Intercompany Rig Profit
| Three Months Ended | Nine Months Ended | |||||||||||||||||||
| June 30, | September 30, | September 30, | ||||||||||||||||||
| 2011 | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Contract drilling revenue | $ | 115,183 | $ | 128,927 | $ | 85,004 | $ | 342,098 | $ | 217,919 | ||||||||||
| Contract drilling operating cost | 64,238 | 73,004 | 45,406 | 190,086 | 132,847 | |||||||||||||||
| Operating profit from contract drilling | 50,945 | 55,923 | 39,598 | 152,012 | 85,072 | |||||||||||||||
|
Add:
Elimination of intercompany rig profit |
5,092 |
|
4,820 |
|
2,888 |
14,955 |
|
4,717 |
||||||||||||
| Operating profit from contract drilling | ||||||||||||||||||||
| before elimination of intercompany | ||||||||||||||||||||
| rig profit | 56,037 | 60,743 | 42,486 | 166,967 | 89,789 | |||||||||||||||
| Contract drilling operating days | 6,695 | 7,220 | 6,021 | 20,129 | 15,894 | |||||||||||||||
| Average daily operating margin before | ||||||||||||||||||||
| elimination of intercompany rig profit | $ | 8,370 | $ | 8,413 | $ | 7,056 | $ | 8,295 | $ | 5,649 | ||||||||||
________________
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, 918-493-7700
Chief
Financial Officer and Treasurer
www.unitcorp.com
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