Unit Corporation (NYSE: UNT) announced today net income of $28.5
million, or $0.60 per diluted share, for the three months ended December
31, 2009, compared to a net loss of $119.8 million, or $2.57 per diluted
share, for the three months ended December 31, 2008. Included in the
fourth quarter 2008 results was a non-cash ceiling test write down of
$282.0 million ($175.5 million after tax, or $3.76 per diluted share).
The ceiling test write down was required to reduce the carrying value of
the company’s oil and natural gas properties due to significantly lower
commodity prices existing at year-end 2008. Excluding the effect of the
ceiling test write down, net income for the fourth quarter of 2008 would
have been $55.7 million, or $1.19 per diluted share (see Non-GAAP
Financial Measures below). Total revenues for the fourth quarter of 2009
were $177.3 million (27% contract drilling, 51% oil and natural gas, and
21% mid-stream). For the fourth quarter of 2008 total revenues were
$291.0 million (53% contract drilling, 37% oil and natural gas, and 10%
mid-stream).
For all of 2009, Unit reported a net loss of $55.5 million, or $1.18 per
diluted share, compared to 2008 net income of $143.6 million, or $3.06
per diluted share. Included in the 2009 results is a previously reported
$281.2 million ($175.1 million after tax, or $3.70 per diluted share)
non-cash ceiling test write down that occurred in the first quarter.
Excluding the effect of the ceiling test write down, net income for 2009
would have been $119.6 million, or $2.52 per diluted share (see Non-GAAP
Financial Measures below). Excluding the effect of the fourth quarter
2008 ceiling test write down discussed above, net income for 2008 would
have been $319.1 million, or $6.80 per diluted share (see Non-GAAP
Financial Measures below). Total revenues for all of 2009 were $709.9
million (33% contract drilling, 50% oil and natural gas, and 15%
mid-stream), compared to $1,358.1 million (46% contract drilling, 41%
oil and natural gas, and 13% mid-stream) for all of 2008.
CONTRACT DRILLING SEGMENT INFORMATION
Average drilling rig utilization for the fourth quarter of 2009 was 36.7
drilling rigs, or 28%, a decrease of 62% from the fourth quarter of
2008, and an increase of 6% from the third quarter of 2009. Contract
drilling rig rates for the fourth quarter of 2009 averaged $14,708 per
day, a decrease of 24%, or $4,622 per day, from the fourth quarter of
2008, and a decrease of 4%, or $652 per day, from the third quarter of
2009. Average operating margins for the fourth quarter of 2009 were
$5,268 per day (before elimination of intercompany drilling rig profit
and bad debt expense of $0.4 million; see Non-GAAP Financial Measures
below) as compared to $9,525 per day (before elimination of intercompany
drilling rig profit and bad debt expense of $7.9 million; see Non-GAAP
Financial Measures below) for the same quarter in 2008, a decrease of
45%. Approximately $619 per day of the fourth quarter 2009 average
operating margin was the result of early termination fees associated
with the cancellation of long-term contracts.
For the year ended December 31, 2009, drilling rig utilization averaged
30%, or 38.9 drilling rigs, as compared to 79%, or 103.1 drilling rigs,
during 2008, a decrease of 62%. 2009 average operating margins were
$6,894 per day (before elimination of intercompany drilling rig profit
and bad debt expense of $1.5 million; see Non-GAAP Financial Measures
below) as compared to $8,987 per day (before elimination of intercompany
drilling rig profit and bad debt expense of $29.4 million for 2008; see
Non-GAAP Financial Measures below), a decrease of 23%. Approximately
$428 per day of the 2009 average operating margin was the result of
early termination fees associated with the cancellation of long-term
contracts.
Currently, Unit has 128 drilling rigs of which 62 are under contract for
work. Contracts with terms ranging from six months to two years in
length are in place for 26 of the 62 drilling rigs under contract for
work. Of the 128 drilling rigs, five are subject to purchase and sales
agreements to be sold to an unaffiliated third party over the next six
months. None of the 62 drilling rigs that are under work contracts is
included in the drilling rigs to be sold. The following table
illustrates this segment’s drilling rig count at the end of each period
and its average utilization rate during the period:
| 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | 1st Qtr 08 | 4th Qtr 07 | ||||||||||
| Rigs | 130 | 130 | 131 | 131 | 132 | 131 | 131 | 129 | 129 | |||||||||
| Utilization | 28% | 26% | 24% | 40% | 74% | 85% | 80% | 78% | 80% | |||||||||
Larry Pinkston, Unit’s Chief Executive Officer and President, said:
“Dayrates continued to be negatively impacted by low commodity prices
and the expiration of long-term contracts. We have, however, experienced
an increase in the demand for our drilling rigs and are receiving
increases in dayrates on rigs focused on horizontal drilling activity.
Recently, we announced the sale of eight of our idle mechanical drilling
rigs to an unaffiliated third party. These rigs range in horsepower from
800 to 1,000. The closing of the sale of three of these rigs occurred
this month bringing our total rig fleet to 128. Three more are scheduled
to close during the remaining part of the first quarter of 2010 with the
last transaction for the remaining two rigs anticipated to close during
the second quarter of 2010. Total proceeds from the sale of all of these
drilling rigs will be $23.9 million, resulting in an estimated gain of
$6.1 million. The proceeds will be used to refurbish and upgrade certain
rigs in our existing fleet that we intend to target toward horizontal
drilling activity. We recently placed into service in our Rocky Mountain
division a 1,500 horsepower, diesel-electric drilling rig that
previously had been placed on hold during 2009 by our customer. At the
completion of the sale of the rigs and with the additional rig recently
placed into service, our drilling rig fleet will total 123.”
OIL AND NATURAL GAS SEGMENT INFORMATION
- Completed 95 gross wells during 2009 with a success rate of 94%.
-
Approximately 63% of anticipated natural gas production and 59% of
anticipated crude oil production is hedged for 2010. -
Plan to participate in the drilling of 175 wells during 2010 with
preliminary production guidance of 66.0 to 67.0 Bcfe.
Fourth quarter 2009 production was 295,000 barrels of oil, in comparison
to 318,000 barrels of oil in the fourth quarter of 2008, a 7% decrease.
Natural gas liquids (NGLs) production during the fourth quarter of 2009
was 346,000 barrels in comparison to 427,000 barrels in the fourth
quarter of 2008, a 19% decrease. Fourth quarter 2009 natural gas
production decreased 15% to 10.5 billion cubic feet (Bcf) from 12.3 Bcf
during the comparable quarter of 2008. Fourth quarter 2009 equivalent
production totaled 14.3 Bcfe, a 15% decrease over the fourth quarter
2008. Total production for 2009 was 60.7 Bcfe, a decrease of 4% over the
63.4 Bcfe produced during 2008.
Unit’s average natural gas price for the fourth quarter of 2009
increased 4% to $5.77 per thousand cubic feet (Mcf) as compared to $5.55
per Mcf for the fourth quarter of 2008. Unit’s average oil price for the
fourth quarter of 2009 was $61.57 per barrel compared to $77.71 per
barrel for the fourth quarter of 2008, a 21% decrease, and Unit’s
average NGLs price for the fourth quarter of 2009 was $26.02 per barrel
compared to $26.17 per barrel for the fourth quarter of 2008, a 1%
decrease. For 2009, Unit’s average natural gas price decreased 27% to
$5.59 per Mcf as compared to $7.62 per Mcf for 2008. Unit’s average oil
price for 2009 was $56.33 per barrel compared to $93.87 per barrel
during 2008, a 40% decrease. Unit’s average NGLs price for 2009 was
$22.81 per barrel compared to $47.42 per barrel during 2008, a 52%
decrease.
For 2010, approximately 63% of the company’s anticipated average daily
natural gas production is hedged and 59% of its anticipated daily oil
production is hedged. The natural gas production is hedged under swap
contracts at a comparable average NYMEX price of $6.95. The average
basis differentials for the swaps are ($0.66). Of the oil hedges, 60%
are under swap contracts at an average price of $61.36 and 40% are under
a collar contract with a floor of $67.50 and a ceiling of $81.53.
The following table illustrates this segment’s production and certain
results for the periods indicated:
| 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | 1st Qtr 08 | 4th Qtr 07 | ||||||||||
| Production, Bcfe |
14.3 |
14.7 |
15.4 |
16.3 |
16.8 |
15.9 |
16.0 |
14.7 |
14.7 |
|||||||||
| Realized Price, Mcfe (1) |
$6.12 |
$5.92 |
$5.75 |
$5.48 |
$6.21 |
$9.49 |
$10.19 |
$8.72 |
$7.66 |
|||||||||
| Wells Drilled (gross) |
37 |
21 |
16 |
21 |
67 |
82 |
72 |
57 |
81 |
|||||||||
| Success Rate |
92% |
90% |
100% |
90% |
90% |
89% |
90% |
86% |
90% |
|||||||||
(1) Realized price includes oil, natural gas liquids, natural gas and
associated hedges.
During 2009, Unit participated in the drilling of 95 wells, of which 89
were completed as producing wells for a success rate of 94% in
comparison to the completion of 278 wells with an 88% success rate
during 2008.
Unit’s exploration and production segment plans to increase activity in
several of its core and emerging operating areas. In the Granite Wash
play, located in the Texas Panhandle and western Oklahoma, the company
owns approximately 95,000 gross and 38,000 net acres. During 2009 we
drilled and operated 13 vertical wells and one horizontal well in the
Texas Panhandle. The vertical wells had an average working interest of
66% and estimated gross reserves of 1.8 Bcfe per well at an average
gross completed well cost of $2.3 million. We have a 70% working
interest in the horizontal well which averaged 4.2 MMcf per day of
natural gas, 500 barrels of oil per day and 600 barrels of NGLs per day,
or 10.8 MMcfe per day, over the initial 30 day flow period beginning in
late December 2009. The well was drilled with a 4,000′ lateral that was
fracture stimulated in 11 stages utilizing approximately 48,000 barrels
of water and 1,000,000 pounds of sand. Estimated ultimate gross reserves
are 6.0 to 8.0 Bcfe at an approximate gross completed well cost of $3.8
million. We drilled our first horizontal Granite Wash well in late 2008
which had a 2,400′ lateral and was fracture stimulated in six stages
utilizing 16,000 barrels of water and 500,000 pounds of sand. The
highest 30 day flow rate achieved from the well was 5.5 MMcfe per day
and the well is currently producing 1.8 MMcfe per day. For 2010, the
company plans to participate in approximately 9 gross (4 net) vertical
wells and 31 gross (14 net) horizontal wells at a total net cost to the
company of approximately $70 million. The Segno Wilcox play, located in
Polk, Tyler and Hardin Counties, Texas, continues to grow. During 2009,
we completed eight wells with an average working interest of 86% at a
75% success rate. The average gross completed well cost was $2.7 million
per well with estimated gross reserves of approximately 3.0 Bcfe per
well. The Wing #3 (100% working interest) was drilled in the fourth
quarter of 2009 and has been selling an average of 5.5 MMcfe per day of
natural gas and 125 barrels of oil per day, or 6.3 MMcfe per day, over a
31 day period beginning in late December 2009. We estimate reserves on
this well between 15.0 to 20.0 Bcfe. We have expanded our Segno prospect
area to the south by entering into a joint exploration agreement with an
undisclosed third party for the use of a proprietary 3-D seismic survey
covering approximately 151 square miles. By drilling and operating
certain wells, we will earn an interest in (i) the wells, (ii) oil and
gas leases covering approximately 29,000 gross acres and (iii) a license
to the 3-D data. For 2010, Unit plans to drill 23 gross (17.5 net) wells
at an approximate net cost of $48 million. In the Haynesville Shale play
of East Texas, Unit owns 16,204 gross acres and 11,302 net acres in
Shelby County and 20,000 gross and 8,700 net acres in Harrison County.
During 2010, the company plans to participate in five horizontal wells
and two vertical wells at an approximate total net cost to the company
of $31 million. In the Marcellus Shale play, Unit owns 197,000 gross and
49,500 net acres, mainly in Somerset County, Pennsylvania. During 2009,
Unit participated in three vertical wells and two horizontal wells at a
total net cost of $7.3 million. One horizontal well is in the early
stages of flowing back after fracture stimulation and the second
horizontal well is scheduled to be fracture stimulated in the second
quarter of 2010. Any wells drilled in 2010 will be determined pending
the results of the two horizontal wells.
Pinkston said: “Our exploration and production segment had a challenging
year in 2009. We reduced our drilling activity substantially during the
first half of the year while commodity prices were decreasing. During
the second half of the year, this segment began to increase its drilling
activity as the cost to drill wells became more economical. We recently
announced our total proved reserves at December 31, 2009 were 577.0 Bcfe
of natural gas, a 1% increase over our 2008 total proved reserves. On a
debt-adjusted per share basis, December 31, 2009 total proved reserves
increased 10% over 2008 total proved reserves. New SEC rules for
measuring reserves, including the method of determining year-end prices,
primarily contributed to the negative revisions to our reserves of 38
Bcfe. Our production replacement for 2009 was 175%, excluding the
negative revisions, or 113% when those revisions are taken into account.
During 2010, we plan to participate in the drilling of 175 wells, an 84%
increase over 2009. Our preliminary annual production guidance for 2010
is approximately 66.0 to 67.0 Bcfe, an increase of 9% to 10% over 2009.”
MID-STREAM SEGMENT INFORMATION
-
Increased 2009 processing volumes per day and liquids sold volumes per
day by 12% and 24%, respectively. - 37 new wells connected to existing systems during 2009.
Fourth quarter of 2009 processing volumes of 77,501 MMBtu per day and
liquids sold volumes of 263,668 gallons per day increased 7% and 34%,
respectively, over the fourth quarter of 2008. Fourth quarter 2009
gathering volumes were 177,145 MMBtu per day, a 6% decrease over fourth
quarter of 2008. Operating profit (as defined in the Selected Financial
and Operational Highlights) for the fourth quarter was $9.0 million, an
increase of $2.8 million from the third quarter of 2009, due primarily
to increased liquids prices and increases in liquids sold and processed
volumes, which resulted in increased processing margins.
For 2009, processing volumes of 75,908 MMBtu per day and liquids sold
volumes of 243,492 gallons per day increased 12% and 24%, respectively,
from 2008. Gathering volumes for 2009 were 183,989 MMBtu per day, a 7%
decrease from 2008.
The following table illustrates certain results from this segment’s
operations for the periods indicated:
| 4th Qtr 09 | 3rd Qtr 09 | 2nd Qtr 09 | 1st Qtr 09 | 4th Qtr 08 | 3rd Qtr 08 | 2nd Qtr 08 | 1st Qtr 08 | 4th Qtr 07 | ||||||||||
|
Gas gathered MMBtu/day |
177,145 | 179,047 | 187,666 | 192,320 | 187,585 | 195,914 | 205,397 | 200,697 | 212,786 | |||||||||
|
Gas processed MMBtu/day |
77,501 | 77,923 | 75,481 | 72,650 | 72,491 | 71,260 | 67,545 | 59,797 | 59,009 | |||||||||
|
Liquids sold
Gallons/day |
263,668 | 251,830 | 239,121 | 218,762 | 197,428 | 199,805 | 202,130 | 183,924 | 169,897 | |||||||||
Unit’s mid-stream segment operates three natural gas treatment plants,
owns eight processing plants, 33 active gathering systems and 839 miles
of pipeline.
Pinkston said: “During 2009, our mid-stream segment connected 37 new
wells to existing systems and added an additional 69 miles of pipeline.
We are pleased with the volume growth and results that this segment has
been able to achieve during a year of reduced drilling activity by
exploration and production companies. We are optimistic about the growth
opportunities of our mid-stream operations, despite the weak economy.”
FINANCIAL INFORMATION
Unit ended the year with long-term debt of $30.0 million and a debt to
capitalization ratio of 2%. Under the company’s credit facility, the
amount available to be borrowed is the lesser of the amount elected by
the company as the commitment amount (currently $325 million) or the
value of the borrowing base as determined by the lenders under the
credit facility, but not to exceed the maximum credit facility amount of
$400 million. As of October 1, 2009, Unit’s borrowing base was
reaffirmed by its lenders at $475 million. The company recently
increased its 2010 capital expenditures budget for all its business
segments to $494 million from $467, as previously announced. The $27
million increase is for its contract drilling segment, primarily
associated with using the proceeds from the sale of the previously
mentioned drilling rigs to accelerate the refurbishment and upgrading of
existing rigs in its fleet targeted toward horizontal drilling
activities.
MANAGEMENT COMMENT
Larry Pinkston said: “We are pleased with our 2009 fourth quarter and
year end results. 2009 was a challenging year as the weak economy
continued to persist. Our long-term debt at the end of the year was
$30.0 million, $169.5 million less than at year end 2008. The reduction
in our debt was primarily funded from lower capital spending relative to
our cash flow, supported by a strong commodity hedge position, along
with proceeds from the sale of certain Appalachia acreage and related
collection of third party costs. An increase in demand for drilling
activity by exploration and production companies has materialized during
the fourth quarter and we are optimistic about what 2010 holds for Unit.
We believe that we are well positioned to take advantage of any growth
opportunities that prove economic to the company.”
WEBCAST
Unit will webcast its fourth quarter and year end earnings conference
call live over the Internet on February 23, 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 the
ability to meet its future reserve replacement goals, anticipated gas
gathering and processing rates and throughput volumes, the prospective
capabilities of the reserves associated with the Company’s inventory of
future drilling sites, anticipated oil and natural gas prices, the
number of wells to be drilled by the Company’s oil and natural gas
segment, development, operational, implementation and opportunity risks,
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 | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Statement of Income: | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Contract drilling | $ | 47,932 | $ | 155,208 | $ | 236,315 | $ | 622,727 | ||||||||
| Oil and natural gas | 90,480 | 107,354 | 357,879 | 553,998 | ||||||||||||
| Gas gathering and processing | 37,024 | 28,628 | 108,628 | 181,730 | ||||||||||||
| Other | 1,896 | (169 | ) | 7,076 | (362 | ) | ||||||||||
| Total revenues | 177,332 | 291,021 | 709,898 | 1,358,093 | ||||||||||||
| Expenses: | ||||||||||||||||
| Contract drilling: | ||||||||||||||||
| Operating costs | 30,515 | 78,366 | 140,080 | 312,907 | ||||||||||||
| Depreciation | 11,523 | 18,521 | 45,326 | 69,841 | ||||||||||||
| Oil and natural gas: | ||||||||||||||||
| Operating costs | 24,888 | 25,886 | 87,734 | 116,239 | ||||||||||||
| Depreciation, depletion | ||||||||||||||||
| and amortization | 24,881 | 44,794 | 114,681 | 159,550 | ||||||||||||
|
Impairment of oil and natural gas properties |
— |
281,966 |
281,241 |
281,966 |
||||||||||||
| Gas gathering and processing: | ||||||||||||||||
| Operating costs | 28,020 | 24,849 | 87,908 | 150,466 | ||||||||||||
| Depreciation | ||||||||||||||||
| and amortization | 3,938 | 3,890 | 16,104 | 14,822 | ||||||||||||
| General and administrative | 6,923 | 5,240 | 24,011 | 25,419 | ||||||||||||
| Interest, net | — | 142 | 539 | 1,304 | ||||||||||||
| Total expenses | 130,688 | 483,654 | 797,624 | 1,132,514 | ||||||||||||
| Income (Loss) Before Income Taxes | 46,644 | (192,633) | (87,726 | ) | 225,579 | |||||||||||
| Income Tax Expense (Benefit): | ||||||||||||||||
| Current | (10,041 | ) | (284 | ) | (223 | ) | 40,877 | |||||||||
| Deferred | 28,172 | (72,501 | ) | (32,003 | ) | 41,077 | ||||||||||
| Total income taxes | 18,131 | (72,785 | ) | (32,226 | ) | 81,954 | ||||||||||
| Net Income (Loss) | $ | 28,513 | $ | (119,848 | ) | $ | (55,500 | ) | $ | 143,625 | ||||||
|
Net Income (Loss) per Common Share: |
||||||||||||||||
| Basic | $ | 0.61 | $ | (2.57 | ) | $ | (1.18 | ) | $ | 3.08 | ||||||
| Diluted | $ | 0.60 | $ | (2.57 | ) | $ | (1.18 | ) | $ | 3.06 | ||||||
| Weighted Average Common | ||||||||||||||||
| Shares Outstanding: | ||||||||||||||||
| Basic | 47,020 | 46,639 | 46,990 | 46,586 | ||||||||||||
| Diluted | 47,503 | 46,639 | 46,990 | 46,909 |
|
|||||||||||
|
|
December 31, | December 31, | ||||||
| 2009 | 2008 | |||||||
| Balance Sheet Data: | ||||||||
| Current assets | $ | 128,095 | $ | 286,585 | ||||
| Total assets | $ | 2,228,399 | $ | 2,581,866 | ||||
| Current liabilities | $ | 105,147 | $ | 196,399 | ||||
| Long-term debt | $ | 30,000 | $ | 199,500 | ||||
| Other long-term liabilities | $ | 81,126 | $ | 75,807 | ||||
| Deferred income taxes | $ | 446,316 | $ | 477,061 | ||||
| Shareholders’ equity |
$ |
1,565,810 | $ | 1,633,099 | ||||
| Twelve Months Ended December 31, | |||||||||
| 2009 | 2008 | ||||||||
| Statement of Cash Flows Data: | |||||||||
|
Cash Flow From Operations before Changes in Operating Assets and |
$ | 380,762 | $ | 730,336 | |||||
| Net Change in Operating Assets and Liabilities | 109,713 | (40,423 | ) | ||||||
| Net Cash Provided by Operating Activities | $ | 490,475 | $ | 689,913 | |||||
| Net Cash Used in Investing Activities | $ | (271,927 | ) | $ | (806,141 | ) | |||
|
Net Cash Provided by (Used in) Financing Activities |
$ |
(217,992 | ) |
$ |
115,736 | ||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Contract Drilling Operations Data: | ||||||||||||||||
| Rigs Utilized | 36.7 | 96.7 | 38.9 | 103.1 | ||||||||||||
| Operating Margins (2) | 36% | 50% | 41% | 50% | ||||||||||||
| Operating Profit Before Depreciation (2) ($MM) | $ | 17.4 | $ | 76.8 | $ | 96.2 | $ | 309.8 | ||||||||
| Oil and Natural Gas Operations Data: | ||||||||||||||||
| Production: | ||||||||||||||||
| Oil – MBbls | 295 | 318 | 1,286 | 1,261 | ||||||||||||
| Natural Gas Liquids – MBbls | 346 | 427 | 1,488 | 1,388 | ||||||||||||
| Natural Gas – MMcf | 10,489 | 12,331 | 44,063 | 47,473 | ||||||||||||
| Average Prices: | ||||||||||||||||
| Oil price per barrel received | $ | 61.57 | $ | 77.71 | $ | 56.33 | $ | 93.87 | ||||||||
| Oil price per barrel received, excluding hedges | $ | 73.02 | $ | 56.20 | $ | 56.64 | $ | 98.02 | ||||||||
| NGLs price per barrel received | $ | 26.02 | $ | 26.17 | $ | 22.81 | $ | 47.42 | ||||||||
| NGLs price per barrel received, excluding hedges | $ | 36.10 | $ | 26.17 | $ | 25.66 | $ | 47.38 | ||||||||
| Natural Gas price per Mcf received | $ | 5.77 | $ | 5.55 | $ | 5.59 | $ | 7.62 | ||||||||
| Natural Gas price per Mcf received, excluding hedges | $ | 3.90 | $ | 4.54 | $ | 3.26 | $ | 7.53 | ||||||||
|
Operating Profit Before DD&A and impairment (2) ($MM) |
$ | 65.6 | $ | 81.5 | $ | 270.1 | $ | 437.8 | ||||||||
| Gas Gathering and Processing Operations Data: | ||||||||||||||||
| Gas Gathering – MMBtu/day | 177,145 | 187,585 | 183,989 | 197,367 | ||||||||||||
| Gas Processing – MMBtu/day | 77,501 | 72,491 | 75,908 | 67,796 | ||||||||||||
| Liquids Sold – Gallons/day | 263,668 | 197,428 | 243,492 | 195,837 | ||||||||||||
|
Operating Profit Before Depreciation and Amortization (2) ($MM) |
$ | 9.0 | $ | 3.8 | $ | 20.7 | $ | 31.3 | ||||||||
(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 and impairment, 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 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 twelve months ended December 31,
2009 and 2008. 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 |
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| Three Months Ended | Twelve Months Ended | |||||||||||||||||
| December 31, | December 31, | |||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||||
| (In thousands) | ||||||||||||||||||
|
Net income including effect of impairment of oil and natural gas |
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| Net income (loss) | $ | 28,513 | $ | (119,848 | ) | $ | (55,500 | ) | $ | 143,625 | ||||||||
| Add: | ||||||||||||||||||
|
Impairment of oil and natural gas properties (net of income tax) |
— | 175,524 | 175,072 | 175,524 | ||||||||||||||
|
Net income excluding effect of impairment of oil and natural gas |
$ |
28,513 |
$ |
55,676 |
$ |
119,572 |
$ |
319,149 |
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|
Diluted earnings per share including effect of impairment of oil |
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| Diluted earnings per share | $ | 0.60 | $ | (2.57 | ) | $ | (1.18 | ) | $ | 3.06 | ||||||||
| Add: | ||||||||||||||||||
|
Diluted earnings per share from impairment of oil and natural gas |
— | 3.76 | 3.70 | 3.74 | ||||||||||||||
|
Diluted earnings per share excluding effect of impairment of oil |
$ | 0.60 | $ | 1.19 | $ | 2.52 | $ | 6.80 | ||||||||||
We have included the net income excluding the effect of impairment of
oil and natural gas properties and diluted earnings per share excluding
the effect of 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 |
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| Twelve Months Ended
December 31, |
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| 2009 | 2008 | |||||||
| (In thousands) | ||||||||
| Net cash provided by operating activities | $ | 490,475 | $ | 689,913 | ||||
| Subtract: | ||||||||
| Net change in operating assets and liabilities | (109,713 | ) | 40,423 | |||||
|
Cash flow from operations before changes in operating assets and |
$ | 380,762 | $ | 730,336 | ||||
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 |
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| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Contract drilling revenue | $ | 47,932 | $ | 155,208 | $ | 236,315 | $ | 622,727 | ||||||||
| Contract drilling operating cost | 30,515 | 78,366 | 140,080 | 312,907 | ||||||||||||
| Operating profit from contract drilling | 17,417 | 76,842 | 96,235 | 309,820 | ||||||||||||
| Add: | ||||||||||||||||
|
Elimination of intercompany rig profit and bad debt expense |
377 | 7,922 | 1,549 | 29,381 | ||||||||||||
|
Operating profit from contract drilling before elimination of |
17,794 | 84,764 | 97,784 | 339,201 | ||||||||||||
| Contract drilling operating days | 3,378 | 8,899 | 14,183 | 37,745 | ||||||||||||
|
Average daily operating margin before elimination of rig profit |
$ | 5,268 | $ | 9,525 | $ | 6,894 | $ | 8,987 | ||||||||
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
David T. Merrill, 918-493-7700
Chief
Financial Officer and Treasurer
www.unitcorp.com
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