Unit Corporation (NYSE: UNT) reported net income of $52.4 million, or
$1.09 per diluted share, for the three months ended March 31, 2012. For
the same period in 2011, net income was $41.0 million, or $0.86 per
diluted share. Total revenues for the first quarter of 2012 were $332.4
million (42% contract drilling, 40% oil and natural gas, and 17%
mid-stream), compared to $247.4 million (40% contract drilling, 44% oil
and natural gas, and 16% mid-stream) for the first quarter of 2011.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the first quarter of 2012
was 81.5, an increase of 16% over the first quarter of 2011, and a
decrease of 1% from the fourth quarter of 2011. Per day drilling rig
rates for the first quarter of 2012 averaged $19,838, an increase of
12%, or $2,134, from the first quarter of 2011, and an increase of 3%,
or $508, from the fourth quarter of 2011. Average per day operating
margin for the first quarter of 2012 was $9,414 (before elimination of
intercompany drilling rig profit of $4.3 million). This compares to
$8,077 (before elimination of intercompany drilling rig profit of $5.0
million) for the first quarter of 2011, an increase of 17%, or $1,337.
As compared to the fourth quarter of 2011 ($9,037 before elimination of
intercompany drilling rig profit and bad debt expense of $4.9 million)
first quarter 2012 operating margin increased 4% or $377 – in each case
with regard to the elimination of intercompany drilling rig profit see
Non-GAAP Financial Measures below.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We
are pleased with the results that our contract drilling segment has been
able to attain. The first quarter of 2012 was the eighth consecutive
quarter of increased per day operating margins. As the industry has
continued to transition to drilling horizontal or directional wells, we
have been able to respond to that demand by refurbishing our existing
drilling rigs or adding new drilling rigs. Approximately 96% of our
drilling rigs working today are drilling for oil or natural gas liquids
(NGLs) and approximately 97% are drilling horizontal or directional
wells. During the first quarter of 2012, we sold an idle 600 horsepower
mechanical drilling rig to an unaffiliated third party and placed a new
1,500 horsepower, diesel-electric drilling rig into service in Wyoming
under a three-year contract. Additionally, we are building another new
1,500 horsepower, diesel-electric drilling rig to be used in North
Dakota. The drilling rig will be under a three-year contract and should
be completed during the second quarter of 2012. On completion of the new
drilling rig, we will have 128 drilling rigs in our fleet. Currently, 77
of our drilling rigs are under contract. Long-term contracts (contracts
with original terms ranging from six months to two years in length) are
in place for 53 of those 77 drilling rigs. Of these contracts, 11 are up
for renewal during the second quarter of 2012, 18 during the third
quarter of 2012, eight during the fourth quarter of 2012, and 16 in 2013
and beyond. These contracts include the term contract for the new
drilling rig.”
The following table illustrates Unit’s drilling rig count at the end of
each period and average utilization rate during the period:
| 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | |||||||||||
| Rigs | 127 | 127 | 126 | 123 | 122 | 121 | 123 | 123 | 125 | ||||||||||
| Utilization | 64% | 65% | 63% | 60% | 58% | 59% | 54% | 47% | 40% | ||||||||||
OIL AND NATURAL GAS SEGMENT INFORMATION
-
First quarter 2012 production was 3.3 MMBoe, an increase of 20% over
the first quarter 2011. -
42% of first quarter 2012 production was oil and NGLs compared to 38%
for the first quarter of 2011. -
Production guidance for 2012 is 13.2 to 13.5 MMBoe, an increase of 9%
to 12% over 2011.
First quarter 2012 oil production was 720,000 barrels, in comparison to
556,000 barrels for the same period of 2011, an increase of 30%. NGLs
production during the first quarter of 2012 was 656,000 barrels, an
increase of 37% when compared to 478,000 barrels for the same period of
2011. First quarter 2012 natural gas production increased 11% to 11.4
billion cubic feet (Bcf) compared to 10.2 Bcf for the comparable quarter
of 2011. First quarter 2012 production averaged 35,992 Boe per day, an
increase of 18% over the first quarter of 2011 and an increase of 2%
over the fourth quarter of 2011. Total production for the first quarter
of 2012 was 3.3 MMBoe.
Unit’s average natural gas price, including the effects of hedges, for
the first quarter of 2012 decreased 22% to $3.36 per thousand cubic feet
(Mcf) as compared to $4.28 per Mcf for the first quarter of 2011. Unit’s
average oil price, including the effects of hedges, for the first
quarter of 2012 increased 14% to $95.81 per barrel compared to $84.33
per barrel for the first quarter of 2011. Unit’s average NGLs price,
including the effects of hedges, for the first quarter of 2012 was
$38.81 per barrel compared to $39.61 per barrel for the first quarter of
2011, a decrease of 2%.
For 2012, Unit hedged approximately 6,100 Bbls per day of oil production
and approximately 50,000 MMBtu per day of natural gas production. The
oil production is hedged under swap contracts at an average price of
$97.55 per barrel. The natural gas production is hedged under swap
contracts at a comparable average NYMEX price of $5.09. The average
basis differential for the applicable swaps is ($0.28). For 2012, Unit
hedged NGLs of 1,966 Bbls per day in the first quarter, 926 Bbls per day
in the second quarter, 380 Bbls per day in the third quarter, and 380
Bbls per day in the fourth quarter. The NGLs are hedged under swap
contracts at an average price of $42.53 per barrel in the first quarter,
$41.15 per barrel in the second quarter, $51.28 per barrel in the third
quarter, and $50.28 per barrel in the fourth quarter.
For 2013, Unit has hedged 4,000 Bbls per day of its oil production and
30,000 MMBtu per day of natural gas production. The oil production is
hedged under swap contracts at an average price of $102.68 per barrel.
Of the natural gas production, 10,000 MMBtu per day is hedged with a
swap and 20,000 MMBtu per day is hedged with a collar. The swap
transaction was done at a comparable average NYMEX price of $3.21. The
collar transaction was done at a comparable average NYMEX floor price of
$3.25 and ceiling price of $3.72.
The following table illustrates Unit’s production and certain results
for the periods indicated:
| 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | |||||||||||
|
Oil and NGL Production, MBbl |
1,375.2 |
1,359.9 |
1,197.5 |
1,158.6 |
1,034.0 |
925.5 |
756.5 |
708.6 |
679.4 |
||||||||||
|
Natural Gas Production, Bcf |
11.4 |
11.4 |
11.6 |
10.9 |
10.2 |
10.6 |
10.4 |
9.7 |
10.0 |
||||||||||
| Production, MBoe |
3,275 |
3,255 |
3,123 |
2,983 |
2,739 |
2,698 |
2,478 |
2,325 |
2,352 |
||||||||||
| Production, MBoe/day |
36.0 |
35.4 |
33.9 |
32.8 |
30.4 |
29.3 |
27.0 |
25.6 |
26.1 |
||||||||||
|
Realized price, Boe (1) |
$40.51 |
$42.65 |
$41.75 |
$42.23 |
$40.00 |
$41.58 |
$38.16 |
$38.22 |
$40.92 |
(1) Realized price includes oil, natural gas liquids, natural gas and
associated hedges.
During the first quarter of 2012, in the Marmaton horizontal oil play
located in Beaver County, Oklahoma, Unit had first sales on six wells
with an average working interest of 75%. The initial 30-day average
production rate for the six wells ranged from 30 barrels of oil
equivalent (Boe) per day to 580 Boe per day with an average rate of 263
Boe per day. The average ultimate recovery for a Marmaton horizontal
well is estimated to be 130 MBoe, which is comprised of approximately
78% oil, 14% NGLs, and 8% natural gas. The average completed well cost
is approximately $2.7 million. The net production from Unit’s Marmaton
operated wells for the first quarter 2012 averaged 1,775 barrels of oil
per day, 188 barrels of NGLs per day, and 1,054 Mcf per day, a decrease
of 23% compared to the fourth quarter 2011 due primarily to fewer wells
coming on production during the first quarter. Production in this play
for the first quarter 2012 increased 29% over the first quarter 2011.
For 2012, Unit anticipates running a two drilling rig program in this
play that should result in 30 to 35 gross wells at an approximate net
cost of $70 million. Unit has drilled and fracture stimulated its first
9,500′ extended lateral in this play during the first quarter of 2012
for an estimated cost of $4.2 million. The production rate has been
improving since first oil sales on April 14, 2012 with a current rate of
800 barrels of oil per day, 69 barrels of NGLs per day and 292 Mcf per
day, or an equivalent rate of 918 Boe per day. A second extended lateral
well is scheduled to be drilled in late second quarter. Unit currently
has leases on approximately 102,822 net acres in this play.
In its Granite Wash (GW) play located in the Texas Panhandle, Unit had
first oil and gas sales on 11 horizontal wells with an average working
interest of 84%. The higher than normal number of completed wells during
the quarter was due to a number of wells that were drilled in the fourth
quarter 2011 but were not completed until the first quarter 2012 because
of pipeline hookup delays. The 30-day average production rate for the 11
wells ranged from 1.3 MMcfe per day to 10.0 MMcfe per day with an
average rate of 4.8 MMcfe per day. The net production from Unit’s GW
operated wells for the first quarter 2012 averaged 1,363 barrels of oil
per day, 3,115 barrels of NGLs per day and 25.7 MMcf per day, or an
equivalent rate of 52.6 MMcfe per day, an increase of 8% over the fourth
quarter 2011 and a 19% increase over the first quarter 2011. The first
quarter production stream was comprised of 16% oil, 35% NGLs and 49%
natural gas. The average ultimate recovery for a GW horizontal well is
estimated to be 4.2 to 4.6 Bcfe with an average completed well cost of
approximately $5.5 million. Unit expects to run three to four Unit
drilling rigs drilling horizontal wells in 2012 resulting in
approximately 20 to 25 new operated GW wells at an approximate net cost
of $90 to $100 million.
Unit has recently acquired approximately 60,000 net acres located
primarily in south central Kansas in the developing Mississippian play.
Unit has completed drilling operations on its first horizontal
Mississippian well located in Reno County, Kansas. The well drilled to a
total measured depth of 8,115′ including a 3,532′ lateral. The well was
recently fracture stimulated and is currently in the early stages of
flowing back. Unit’s current plans are to drill two to three additional
horizontal Mississippian wells in the next six months and evaluate the
results before planning any further drilling in this play.
Pinkston said: “We are pleased with the results from our exploration
operations. The first quarter marks the ninth consecutive quarter that
liquids (oil and NGLs) production has increased. Our strategy of
drilling oil or NGLs rich wells is evident in our production results.
Liquids production represented 42% and 38% of total equivalent
production and 71% and 60% of this segment’s revenues during the first
quarter of 2012 and 2011, respectively. First quarter 2012 total
equivalent production increased 20% to 3.3 MMBoe over the first quarter
of 2011, while our total liquids production for the first quarter of
2012 increased 33% over the comparable quarter of 2011. Our annual
production guidance for 2012 is approximately 13.2 to 13.5 MMBoe, an
increase of 9% to 12% over 2011; however, continued weakness in natural
gas prices combined with high natural gas storage levels could result in
curtailments leading to downward revisions to our production guidance.”
MID-STREAM SEGMENT INFORMATION
-
Increased first quarter 2012 liquids sold per day volumes, processed
volumes per day, and gathered volumes per day by 59%, 79% and 35%,
respectively, over the first quarter of 2011. -
Due to high level of Granite Wash play activity around the Hemphill
facility in Texas, an additional 45 MMcf per day gas processing plant
will be installed with completion anticipated during the second
quarter of 2012.
First quarter of 2012 per day processed volumes were 154,825 MMBtu while
liquids sold volumes were 522,829 gallons per day, an increase of 79%
and 59%, respectively, over first quarter of 2011. First quarter 2012
per day gathered volumes were 251,276 MMBtu, an increase of 35% over the
first quarter of 2011. Operating profit (as defined in the Selected
Financial and Operational Highlights) for the first quarter was $9.7
million, a decrease of 10% from the first quarter of 2011, primarily due
to the renegotiation of certain contracts with some of our customers at
one of our processing plants during the first quarter of 2011 that
changed the contracts from percent of index to percent of proceeds.
Compared to the fourth quarter of 2011, operating profit increased 26%
primarily due to increased volumes.
The following table illustrates certain results from this segment’s
operations for the periods indicated:
| 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | 1st Qtr 11 | 4th Qtr 10 | 3rd Qtr 10 | 2nd Qtr 10 | 1st Qtr 10 | |||||||||||
|
Gas gathered MMBtu/day |
251,276 |
257,398 |
228,247 |
190,921 |
185,730 |
188,252 |
183,161 |
183,858 |
180,117 |
||||||||||
|
Gas processed MMBtu/day |
154,825 |
156,721 |
129,820 |
90,737 |
86,445 |
85,195 |
84,175 |
82,699 |
76,513 |
||||||||||
|
Liquids sold
Gallons/day |
522,829 |
511,410 |
449,604 |
356,484 |
328,333 |
291,186 |
260,519 |
279,736 |
253,707 |
||||||||||
Pinkston said: “Liquids sold volumes continue to increase and gas
gathered and processed volumes remain strong. Our Hemphill County
facility in Texas is currently processing approximately 100 MMcf per
day. Due to the continued high level of activity around the Hemphill
facility we will be installing an additional 45 MMcf per day gas
processing plant which will increase this facility’s processing capacity
to approximately 160 MMcf per day. This new plant should be completed
during the second quarter of 2012. At our Cashion facility, we are
continuing to connect new wells to the system and due to this activity
have installed an additional gas processing plant. The installation of
the new 25 MMcf per day high efficiency turbo-expander processing plant
has been completed and became operational at the end of March 2012. With
the installation of this new plant, our total processing capacity
increased to approximately 50 MMcf per day at our Cashion facility. We
are also very active in the Mississippian play in north central
Oklahoma. We completed construction of a new gathering system and gas
processing plant in Grant County, Oklahoma during the fourth quarter of
2011. This system consists of approximately seven miles of gathering
pipeline and a gas processing plant. Also in this area, we have begun
construction of another gathering system and processing plant in Noble
and Kay counties in Oklahoma. This system will initially consist of
approximately 10 miles of 12″ and 16” pipe with a 10 MMcf per day gas
processing plant that will be upgraded to a 30 MMcf per day gas
processing plant in the fourth quarter of 2012.
“Along with the activities in the mid-continent area, we are continuing
to expand operations in the Appalachian region. The Bruceton Mills
gathering system located in West Virginia became operational in the
fourth quarter of 2011. In addition to the Bruceton Mills gathering
system, construction continues on an additional gathering facility in
Allegheny and Butler counties, Pennsylvania. The first phase of this
project consists of approximately seven miles of gathering pipeline and
a compressor station. The first well has been connected to this system
and is currently flowing into a third party transmission line with an
additional five wells scheduled to be connected in the second quarter of
2012.”
FINANCIAL INFORMATION
Unit ended the first quarter with working capital of $37.9 million,
long-term debt of $315.8 million ($250 million of senior subordinated
notes and $65.8 million under its senior credit agreement), and a debt
to capitalization ratio of 14%. Under its credit agreement, 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.
MANAGEMENT COMMENT
Larry Pinkston said: “Our first quarter 2012 operating results were
solid. We continue to focus our exploration efforts on our oil and
natural gas liquids rich plays like the Granite Wash and Marmaton
formations. For the contract drilling segment, we plan to 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 also
pursuing additional opportunities to grow its operations. We are
optimistic about 2012, and our balance sheet is well positioned to take
advantage of growth opportunities that may arise in all three of our
business segments during the year.”
WEBCAST
Unit will webcast its first quarter earnings conference call live over
the Internet on Tuesday, May 1, 2012 at 11:00 a.m. Eastern Time. To
listen to the live call, please go to www.unitcorp.com
at least fifteen minutes before 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 | |||||||||
| March 31, | |||||||||
| 2012 | 2011 | ||||||||
| Statement of Operations: | |||||||||
| Revenues: | |||||||||
| Contract drilling | $ | 140,906 | $ | 97,988 | |||||
| Oil and natural gas | 133,772 | 109,834 | |||||||
| Gas gathering and processing | 57,295 | 39,764 | |||||||
| Other, net | 455 | (181 | ) | ||||||
| Total revenues | 332,428 | 247,405 | |||||||
| Expenses: | |||||||||
| Contract drilling: | |||||||||
| Operating costs | 76,173 | 52,844 | |||||||
| Depreciation | 21,328 | 17,297 | |||||||
| Oil and natural gas: | |||||||||
| Operating costs | 35,609 | 30,781 | |||||||
| Depreciation, depletion and amortization | 52,197 | 40,268 | |||||||
| Gas gathering and processing: | |||||||||
| Operating costs | 47,613 | 29,055 | |||||||
| Depreciation and amortization | 5,134 | 3,773 | |||||||
| General and administrative | 7,004 | 6,892 | |||||||
| Interest, net | 1,826 | 54 | |||||||
| Total expenses | 246,884 | 180,964 | |||||||
| Income Before Income Taxes | 85,544 | 66,441 | |||||||
| Income Tax Expense: | |||||||||
| Current | — | — | |||||||
| Deferred | 33,105 | 25,414 | |||||||
| Total income taxes | 33,105 | 25,414 | |||||||
| Net Income | $ | 52,439 | $ | 41,027 | |||||
| Net Income per Common Share: | |||||||||
| Basic | $ | 1.10 | $ | 0.86 | |||||
| Diluted | $ | 1.09 | $ | 0.86 | |||||
| Weighted Average Common Shares Outstanding: | |||||||||
| Basic | 47,829 | 47,584 | |||||||
| Diluted | 48,126 | 47,905 | |||||||
| March 31, | December 31, | ||||||||
| 2012 | 2011 | ||||||||
| Balance Sheet Data: | |||||||||
| Current assets | $ | 224,117 | $ | 228,465 | |||||
| Total assets | $ | 3,328,057 | $ | 3,256,720 | |||||
| Current liabilities | $ | 186,255 | $ | 212,750 | |||||
| Long-term debt | $ | 315,800 | $ | 300,000 | |||||
| Other long-term liabilities | $ | 110,687 | $ | 113,830 | |||||
| Deferred income taxes | $ | 714,877 | $ | 683,123 | |||||
| Shareholders’ equity | $ | 1,999,079 | $ | 1,947,017 | |||||
| Three Months Ended March 31, | |||||||||
| 2012 | 2011 | ||||||||
| Statement of Cash Flows Data: | |||||||||
| Cash Flow From Operations before Changes | |||||||||
| in Operating Assets and Liabilities (1) | $ | 170,876 | $ | 134,697 | |||||
| Net Change in Operating Assets and Liabilities |
(22,929 |
) |
(13,492 |
) |
|||||
| Net Cash Provided by Operating Activities | $ | 147,947 | $ | 121,205 | |||||
| Net Cash Used in Investing Activities |
$ |
(189,419 |
) |
$ |
(169,212 |
) |
|||
| Net Cash Provided by Financing Activities | $ | 41,832 | $ | 47,884 | |||||
| Three Months Ended March 31, | |||||||||
| 2012 | 2011 | ||||||||
| Contract Drilling Operations Data: | |||||||||
| Rigs Utilized | 81.5 | 70.0 | |||||||
| Operating Margins (2) | 46 | % | 46 | % | |||||
| Operating Profit Before | |||||||||
| Depreciation (2) ($MM) | $ | 64.7 | $ | 45.1 | |||||
| Oil and Natural Gas Operations Data: | |||||||||
| Production: | |||||||||
| Oil – MBbls | 720 | 556 | |||||||
| Natural Gas Liquids – MBbls | 656 | 478 | |||||||
| Natural Gas – MMcf | 11,400 | 10,231 | |||||||
| Average Prices: | |||||||||
| Oil price per barrel received | $ | 95.81 | $ | 84.33 | |||||
| Oil price per barrel received, excluding hedges | $ | 100.16 | $ | 90.78 | |||||
| NGLs price per barrel received | $ | 38.81 | $ | 39.61 | |||||
| NGLs price per barrel received, excluding hedges | $ | 37.38 | $ | 40.36 | |||||
| Natural Gas price per Mcf received | $ | 3.36 | $ | 4.28 | |||||
| Natural Gas price per Mcf received, excluding hedges | $ | 2.45 | $ | 3.85 | |||||
| Operating Profit Before DD&A (2) ($MM) | $ | 98.2 | $ | 79.1 | |||||
| Mid-Stream Operations Data: | |||||||||
| Gas Gathering – MMBtu/day | 251,276 | 185,730 | |||||||
|
Gas Processing – MMBtu/day |
154,825 | 86,445 | |||||||
|
Liquids Sold – Gallons/day |
522,829 | 328,333 | |||||||
| Operating Profit Before Depreciation | |||||||||
| and Amortization (2) ($MM) | $ | 9.7 | $ | 10.7 | |||||
________________
(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
accounting 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 and bad debt expense.
Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three months ended March 31, 2012 and 2011
and December 31, 2011. 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
| March 31, | |||||||||
| 2012 | 2011 | ||||||||
| (In thousands) | |||||||||
| Net cash provided by operating activities | $ | 147,947 | $ | 121,205 | |||||
| Subtract: | |||||||||
| Net change in operating assets and liabilities | (22,929 | ) | (13,492 | ) | |||||
| Cash flow from operations before changes | |||||||||
| in operating assets and liabilities | $ | 170,876 | $ | 134,697 | |||||
________________
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 and Bad
Debt Expense
|
|
Three Months Ended |
||||||||
| March 31, | December 31, | ||||||||
| 2012 | 2011 | 2011 | |||||||
| (In thousands) | |||||||||
| Contract drilling revenue | $ | 140,906 | $97,988 | $142,553 | |||||
| Contract drilling operating cost | 76,173 | 52,844 | 79,813 | ||||||
| Operating profit from contract drilling | 64,733 | 45,144 | 62,740 | ||||||
|
Add: Elimination of intercompany rig profit and bad debt expense |
4,284 |
5,044 |
4,945 |
||||||
| Operating profit from contract drilling | |||||||||
| before elimination of intercompany | |||||||||
| rig profit and bad debt expense | 69,017 | 50,188 | 67,685 | ||||||
| Contract drilling operating days | 7,331 | 6,214 | 7,490 | ||||||
| Average daily operating margin before | |||||||||
|
elimination of intercompany rig profit and bad debt expense |
$ |
9,414 |
$8,077 |
$9,037 |
|||||
________________
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 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
David T. Merrill, 918-493-7700
Chief
Financial Officer and Treasurer
www.unitcorp.com
Recent Comments