Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the second quarter of 2013. Highlights include:
-
Adjusted non-GAAP net income for the quarter was $48.8 million, or
$1.01 per diluted share (see Non-GAAP Financial Measures below). -
Total production for the quarter was 4.1 million barrels of oil
equivalent (MMBoe), an increase of 23% over the second quarter of 2012. -
Production guidance for 2013 is being increased to between 16.4 and
16.9 MMBoe. -
Total liquids (oil and natural gas liquids) production for the quarter
increased 23% over the comparable quarter of 2012. - Sold two idle 2,000 horsepower drilling rigs.
-
Mid-stream segment’s liquids volumes per day and gathered volumes per
day increased by 21% and 20%, respectively, over the first quarter of
2013. -
Mid-stream operating profit (as defined in the Selected Financial and
Operational Highlights) for the quarter was $11.1 million, an increase
of 39% over the first quarter of 2013.
Net income for the quarter was $59.0 million, or $1.22 per diluted
share, compared to a loss of $19.3 million, or $0.40 per diluted share,
for the second quarter of 2012. Net income included the effect of a
$16.5 million ($10.2 million after tax) increase in earnings from the
unrealized value of commodity derivatives. Without this increase, net
income would have been $48.8 million, or $1.01 per diluted share (see
Non-GAAP Financial Measures below). Total revenues for the quarter were
$340.4 million (48% oil and natural gas, 31% contract drilling, and 21%
mid-stream), compared to $327.8 million (40% oil and natural gas, 45%
contract drilling, and 15% mid-stream) for the second quarter of 2012.
Net income for the six months ended June 30, 2013 was $99.2 million, or
$2.05 per diluted share, compared to $33.1 million, or $0.69 per diluted
share, for the first six months of 2012. Net income for the first six
months of 2013 included the effect of a $9.6 million ($5.9 million after
tax) increase in earnings from the unrealized value of commodity
derivatives. Without this increase, net income for the first six months
of 2013 would have been $93.3 million, or $1.93 per diluted share (see
Non-GAAP Financial Measures below). Total revenues for the first six
months of 2013 were $659.0 million (48% oil and natural gas, 32%
contract drilling, and 20% mid-stream), compared to $661.8 million (40%
oil and natural gas, 44% contract drilling, and 16% mid-stream) for the
first six months of 2012.
OIL AND NATURAL GAS SEGMENT INFORMATION
Unit’s production results reflect its focus on drilling oil or natural
gas liquids (NGLs) rich wells. Liquids production represented 44% of
total equivalent production for the quarter. Total equivalent production
for the quarter increased 23% over the second quarter of 2012 to 4.1
MMBoe, while total liquids production increased 23% over the comparable
quarter of 2012. Liquids production has increased 144% since the first
quarter of 2009 when Unit began focusing on increasing its liquids
production. Second quarter 2013 oil production was 859,000 barrels,
compared to 786,000 barrels for the same period of 2012, an increase of
9%. NGLs production for the quarter was 935,000 barrels, an increase of
39% when compared to 674,000 barrels for the same period of 2012.
Natural gas production increased 23% to 13.9 billion cubic feet (Bcf)
compared to 11.3 Bcf for the comparable quarter of 2012. Total
production for the first six months of 2013 was 8.1 MMBoe.
Unit’s average natural gas price for the quarter increased 20% to $3.65
per thousand cubic feet (Mcf) compared to $3.03 per Mcf for the second
quarter of 2012. Unit’s average oil price for the quarter increased 3%
to $94.89 per barrel compared to $92.43 per barrel for the second
quarter of 2012. Unit’s average NGLs price for the quarter was $30.32
per barrel compared to $32.34 per barrel for the second quarter of 2012,
a decrease of 6%. For the first six months of 2013, Unit’s average
natural gas price increased 9% to $3.47 per Mcf as compared to $3.19 per
Mcf for the first six months of 2012. Unit’s average oil price for the
first six months of 2013 was $95.05 per barrel compared to $94.04 per
barrel during the first six months of 2012, a 1% increase. Unit’s
average NGLs price for the first six months of 2013 was $32.47 per
barrel compared to $35.53 per barrel during the first six months of
2012, a 9% decrease. All prices reflected in this paragraph include the
effects of hedges.
For 2013, Unit has hedged 8,330 Bbls per day of its oil production and
100,000 MMBtu per day of natural gas production. The oil production is
hedged under swap contracts at an average price of $97.94 per barrel. Of
the natural gas production, 80,000 MMBtu per day is hedged with swaps
and 20,000 MMBtu per day is hedged with a collar. The swap transactions
were at a comparable average NYMEX price of $3.65. The collar
transaction was at a comparable average NYMEX floor price of $3.25 and
ceiling price of $3.72.
For 2014, Unit has hedged 7,000 Bbls per day of its oil production and
50,000 MMBtu per day of natural gas production. Of the oil production,
3,000 Bbls per day is hedged with swaps and 4,000 Bbls per day is hedged
with collars. The swap transactions were at an average price of $91.77.
The collar transactions were at an average floor price of $90.00 and
ceiling price of $96.08. The natural gas production is hedged under swap
contracts at a comparable average NYMEX price of $4.24 per MMBtu.
The following table illustrates Unit’s production and realized prices
for the periods indicated:
2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | |||||||||||||||||||||||||||
Oil and NGL Production, MBbl |
1,794.1 |
1,600.6 |
1,694.1 |
1,545.8 |
1,460.2 |
1,375.2 |
1,359.9 |
1,197.5 |
1,158.6 |
||||||||||||||||||||||||||
Natural Gas Production, Bcf |
13.9 |
14.2 |
14.5 |
11.7 |
11.3 |
11.4 |
11.4 |
11.6 |
10.9 |
||||||||||||||||||||||||||
Production, MBoe |
4,109 |
3,971 |
4,115 |
3,498 |
3,341 |
3,275 |
3,255 |
3,123 |
2,983 |
||||||||||||||||||||||||||
Production, MBoe/day |
45.2 |
44.1 |
44.7 |
38.0 |
36.7 |
36.0 |
35.4 |
33.9 |
32.8 |
||||||||||||||||||||||||||
Realized Price, Boe (1) |
$ |
39.10 |
$ |
37.99 |
$ |
39.56 |
$ |
37.99 |
$ |
38.49 |
$ |
40.51 |
$ |
42.65 |
$ |
41.75 |
$ |
42.23 |
(1) Realized price includes oil, natural gas liquids, natural gas and
associated hedges.
The Wilcox play in southeast Texas continues to produce strong results
with average daily production for the quarter increasing approximately
9% and 17% compared to the first quarter 2013 and the second quarter
2012, respectively. This increase was primarily the result of two new
vertical well completions and several significant behind pipe
recompletions in previously drilled wells. Unit anticipates this
production momentum will continue into the third quarter. In the “Gilly”
Lower Wilcox field, at the end of the second quarter the resource
potential increased approximately 31% compared to year end to 302 gross
Bcfe (220 net Bcfe), primarily because of data obtained from drilling
and testing new wells in the field. Subsequent to the end of the second
quarter, Unit drilled an additional well outside the known limits of
existing production on the west side of the “Gilly” field that logged
approximately 250 feet of potential pay. The well is scheduled to be
tested during the third quarter and could result in another increase to
the overall estimated resource potential for the field. Additional
vertical field wells are planned later this year to further delineate
the lateral extent of the field. Drilling operations have also started
on Unit’s first horizontal Wilcox well located within the “Gilly” field.
This well is targeting one of the lower pay sands at a vertical depth of
approximately 14,500 feet with a projected 2,800 foot lateral. The
location of the well is designed to penetrate and case off the majority
of the shallower field pays for potential future production before
drilling the horizontal part of the well. Results from the horizontal
well are anticipated near the end of the third quarter. Approximately
one mile north of the “Gilly” Field, Unit discovered a new productive
fault block with the completion of two recent wells. Unit plans to drill
a third well during the third quarter to further delineate the potential
of the discovery. For the remainder of 2013, Unit is adding a second
Unit rig in its Wilcox play which should result in a total of 12 to 14
gross wells drilled in this play for the year at a net cost of
approximately $78 million.
In Unit’s Mississippian play in south central Kansas, the installation
of the pipeline and processing infrastructure by Superior Pipeline is
underway with an estimated completion in mid-August 2013. Unit resumed
drilling in the prospect in late July and plans to work one or two Unit
drilling rigs for the remainder of 2013. Since the initial well
completion in this play in May 2012 through the end of the second
quarter 2013, Unit has completed seven horizontal wells in the prospect
area with five of the seven wells having sufficient production data to
discuss results. The average 30 day initial production (IP) rate for the
five wells is approximately 238 Boe per day and the preliminary reserve
range is estimated at 125 MBoe to 180 MBoe comprising approximately 58%
liquids. Average production for the second quarter was up 146% over the
previous quarter. Unit has approximately 118,000 net acres in the
Mississippian play and plans to spend approximately $40 million (net)
drilling and completing approximately 13 gross wells during 2013. Unit
has a 100% working interest in all seven of the completed horizontal
wells.
In its Granite Wash (GW) play in the Texas Panhandle, Unit has four Unit
rigs drilling and will potentially add a fifth Unit rig in August and a
sixth Unit rig in October. For the first half of 2013, Unit had first
sales on eight horizontal wells, having an average peak 30 day IP rate
of 4.5 MMcfe per day at an average working interest of 96%. Subsequent
to the second quarter, Unit has completed drilling operations on three
GW horizontal wells and is drilling two GW horizontal wells on leasehold
acquired from the recent Noble acquisition. Completion and first oil and
gas sales for these wells is estimated to occur during the fourth
quarter 2013. For 2013, Unit anticipates completing approximately 28
gross horizontal wells at an approximate net cost of $145 million.
In the Marmaton horizontal oil play in Beaver County, Oklahoma, Unit
completed 23 wells through the second quarter of 2013 with an average
working interest of 77%. The average 30 day peak rate for second quarter
wells was approximately 350 Boe, which is in line with expectations.
Average net daily production for the second quarter was approximately
3,800 barrels of oil equivalent per day which is an increase of
approximately 22% as compared to the second quarter 2012. Development of
the field is continuing on one well per 640 acre spacing. Unit has
leases on approximately 115,000 net acres in this play with
approximately 53% of the leasehold held by production. Unit anticipates
continuing the two Unit rig program in this play which should result in
approximately 46 gross wells being completed during 2013 at an
approximate net cost of $105 million.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We
are pleased with the results from our exploration operations, and we are
excited about our opportunities for growth. Production has grown during
the second quarter of 2013 from the first quarter of 2013 due
principally to our gradual ramp up in company operated drilling rigs. We
are operating 11 drilling rigs and plan to add additional drilling rigs
throughout 2013 depending on market conditions. Unit’s annual production
guidance for 2013 is being increased to between 16.4 to 16.9 MMBoe, an
increase of 15% to 19% over 2012.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the second quarter of 2013
was 65.2, a decrease of 15% from the second quarter of 2012, and a
decrease of 2% from the first quarter of 2013. Per day drilling rig
rates for the second quarter of 2013 averaged $19,601, a decrease of 3%,
or $527, from the second quarter of 2012, and essentially unchanged from
the first quarter of 2013. Average per day operating margin for the
second quarter of 2013 was $7,597 (before elimination of intercompany
drilling rig profit of $3.7 million). This compares to $11,130 (before
elimination of intercompany drilling rig profit of $4.7 million) for the
second quarter of 2012, a decrease of 32%, or $3,533. As compared to the
first quarter of 2013 ($7,534 before elimination of intercompany
drilling rig profit of $3.4 million), second quarter 2013 operating
margin increased 1% or $63 (in each case regarding eliminating
intercompany drilling rig profit see Non-GAAP Financial Measures below).
For the second quarter of 2012 average operating margins included early
termination fees of approximately $2,188 per day from the cancellation
of certain long-term contracts.
For the first six months of 2013, Unit averaged 65.8 drilling rigs
working, a decrease of 17% from 79.1 drilling rigs working during the
first six months of 2012. Average per day operating margin for the first
six months of 2013 was $7,565 (before elimination of intercompany
drilling rig profit of $7.1 million) as compared to $10,246 (before
elimination of intercompany drilling rig profit of $9.0 million) for the
first six months of 2012, a decrease of 26% (in each case regarding
eliminating intercompany drilling rig profit see Non-GAAP Financial
Measures below). For the first six months of 2012 average operating
margins included early termination fees of approximately $1,109 per day
from the cancellation of certain long-term contracts.
Larry Pinkston said: “Drilling rig demand has been fairly flat during
the first six months of 2013. Operators are continuing to focus on
shallower oil plays and liquids rich plays which provide the opportunity
to put more of our 750 to 1,000 horsepower drilling rigs to work. Almost
all of our drilling rigs working today are drilling for oil or NGLs.
Recently, we sold two 2,000 horsepower drilling rigs, bringing our
fleet’s total to 125. Of the 125 drilling rigs, we have 65 under
contract. Long-term contracts (contracts with original terms ranging
from six months to two years in length) are in place for 27 of those 65
drilling rigs. Of these contracts, 13 are up for renewal during the
third quarter of 2013, three during the fourth quarter of 2013, and 11
in 2014 and beyond. We are constructing a new prototype 1,500 horsepower
AC electric drilling rig of proprietary design. The drilling rig is
expected to be operational in the fourth quarter of 2013 and will
operate initially for our oil and natural gas segment.”
The following table illustrates Unit’s drilling rig count at the end of
each period and average utilization rate during the period:
2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | |||||||||||||||||||
Rigs | 126 | 127 | 127 | 127 | 128 | 127 | 127 | 126 | 123 | ||||||||||||||||||
Utilization | 51% | 52% | 50% | 58% | 60% | 64% | 65% | 63% | 60% | ||||||||||||||||||
MID-STREAM SEGMENT INFORMATION
Second quarter of 2013 per day gathered volumes were 326,039 Mcf, an
increase of 24% over the second quarter of 2012. Per day liquids sold
and processed volumes decreased 19% and 4%, respectively, as compared to
the second quarter of 2012. Compared to the first quarter of 2013,
gathered volumes per day, liquids sold volumes per day, and processed
volumes per day increased 20%, 21% and 6%, respectively. Operating
profit (as defined in the Selected Financial and Operational Highlights)
for the second quarter of 2013 was $11.1 million, an increase of 50%
over the second quarter of 2012 and an increase of 39% over the first
quarter of 2013.
The following table illustrates certain results from this segment’s
operations for the periods indicated:
2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | 2nd Qtr 11 | |||||||||||||||||||
Gas gathered Mcf/day |
326,039 |
272,831 |
279,990 |
241,271 |
262,269 |
217,404 |
222,436 |
198,625 |
168,030 |
||||||||||||||||||
Gas processed Mcf/day |
138,130 |
129,857 |
131,570 |
134,907 |
144,257 |
125,231 |
126,628 |
104,351 |
71,561 |
||||||||||||||||||
Liquids sold
Gallons/day |
508,189 |
420,291 |
441,973 |
576,889 |
629,350 |
522,829 |
511,410 |
449,604 |
356,484 |
||||||||||||||||||
Larry Pinkston said: “In the Mississippian play in north central
Oklahoma, our Bellmon system consists of approximately 136 miles of
pipe. In the first quarter of 2013, we completed the installation of a
second processing plant at the Bellmon facility, a 30 MMcf per day
cryogenic plant. Due to increasing volumes, we are installing an
additional 60 MMcf per day processing plant at our Bellmon facility
expected to be operational in the fourth quarter of 2013. At our
Hemphill facility in Hemphill County, Texas, we now can process 135 MMcf
per day of our own and third party Granite Wash natural gas production
after relocating two processing plants from Hemphill to the new Reno
facility. We are also completing two pipeline extension projects for a
total cost of approximately $5.7 million, which will allow us to connect
additional production from our oil and natural gas segment to this
system. In Reno County, Kansas, we are constructing a new gathering
system and processing facility. This system will comprise 35 miles of
gathering pipeline and two processing plants which were relocated from
our Hemphill facility, a 5 MMcf per day refrigeration plant and a 20
MMcf per day turbo expander plant. At this facility, we are currently
only gathering gas but are in the process of installing two processing
plants that are expected to be operational in the third quarter of 2013.
“In the Appalachian area, we are continuing to develop our Pittsburgh
Mills gathering system in Allegheny County, Pennsylvania. We have
completed the 1st phase of this project which comprises
approximately 14 miles of gathering pipeline and related compressor
station in which we have installed three compressors. We have 19 wells
connected to this system with gathered volume of approximately 68 MMcf
per day.”
FINANCIAL INFORMATION
Unit ended the second quarter with long-term debt of $715.5 million
($645.5 million of senior subordinated notes and $70.0 million under its
credit agreement), and a debt to capitalization ratio of 26%. Under its
credit agreement, the amount available for Unit to borrow is the lesser
of the amount Unit elects as the commitment amount ($500 million) or the
value of its borrowing base as determined by the lenders ($800 million),
but in either event not to exceed $900 million.
MANAGEMENT COMMENT
Larry Pinkston said: “We are pleased with the performance of all three
segments and we are excited about continued growth opportunities for
2013. Each segment is moving forward on key initiatives which should
create additional shareholder value for years to come. We continue to
maintain a conservative financial profile. We are well positioned for
continued growth and to take advantage of new opportunities that may
arise.”
WEBCAST
Unit will webcast its second quarter earnings conference call live over
the Internet on August 6, 2013 at 10:00 a.m. Central Time (11:00 a.m.
Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm
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 on the New York Stock Exchange under the symbol UNT. For more
information about Unit Corporation, visit its website at http://www.unitcorp.com.
FORWARD-LOOKING STATEMENT
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. Several risks and uncertainties could cause actual results
to differ materially from these statements, including the 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, and 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 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
because 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, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Statement of Operations: | ||||||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas | $ | 164,799 | $ | 131,166 | $ | 318,408 | $ | 266,931 | ||||||||
Contract drilling | 105,005 | 146,872 | 212,533 | 287,778 | ||||||||||||
Gas gathering and processing | 70,617 | 49,747 | 128,012 | 107,042 | ||||||||||||
Total revenues | 340,421 | 327,785 | 658,953 | 661,751 | ||||||||||||
Expenses: | ||||||||||||||||
Oil and natural gas: | ||||||||||||||||
Operating costs | 44,994 | 33,279 | 88,032 | 68,888 | ||||||||||||
Depreciation, depletion, and amortization |
55,335 | 57,153 | 107,318 | 109,350 | ||||||||||||
Impairment of oil and natural gas properties |
— |
115,874 | — | 115,874 | ||||||||||||
Contract drilling: | ||||||||||||||||
Operating costs | 63,590 | 74,819 | 129,592 | 150,992 | ||||||||||||
Depreciation | 17,908 | 21,238 | 35,168 | 42,566 | ||||||||||||
Gas gathering and processing: | ||||||||||||||||
Operating costs | 59,557 | 42,363 | 108,967 | 89,976 | ||||||||||||
Depreciation and amortization | 8,214 | 5,312 | 15,370 | 10,446 | ||||||||||||
General and administrative | 9,679 | 8,376 | 18,352 | 15,380 | ||||||||||||
Gain on disposition of assets | (3,483 | ) | (651 | ) | (3,399 | ) | (1,239 | ) | ||||||||
Total operating expenses | 255,794 | 357,763 | 499,400 | 602,233 | ||||||||||||
Income (loss) from operations | 84,627 | (29,978 | ) | 159,553 | 59,518 | |||||||||||
Other income (expense): | ||||||||||||||||
Interest, net | (4,591 | ) | (2,542 | ) | (8,152 | ) | (4,368 | ) | ||||||||
Gain (loss) on derivatives | 16,344 | 1,387 | 10,420 | (606 | ) | |||||||||||
Other | (91 | ) | 69 | (157 | ) | (64 | ) | |||||||||
Total other income (expense) | 11,662 | (1,086 | ) | 2,111 | (5,038 | ) | ||||||||||
Income (loss) before income taxes | 96,289 | (31,064 | ) | 161,664 | 54,480 | |||||||||||
Income tax expense (benefit): | ||||||||||||||||
Current | 2,117 | (2,066 | ) | 4,634 | (2,066 | ) | ||||||||||
Deferred | 35,165 | (9,696 | ) | 57,817 | 23,409 | |||||||||||
Total income taxes | 37,282 | (11,762 | ) | 62,451 | 21,343 | |||||||||||
Net income (loss) | $ | 59,007 | $ | (19,302 | ) | $ | 99,213 | $ | 33,137 | |||||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 1.22 | $ | (0.40 | ) | $ | 2.06 | $ | 0.69 | |||||||
Diluted | $ | 1.22 | $ | (0.40 | ) | $ | 2.05 | $ | 0.69 | |||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 48,208 | 47,906 | 48,162 | 47,868 | ||||||||||||
Diluted | 48,506 | 47,906 | 48,491 | 48,113 |
June 30, | December 31, | ||||||||
2013 | 2012 | ||||||||
Balance Sheet Data: | |||||||||
Current assets | $ | 199,669 | $ | 195,644 | |||||
Total assets | $ | 3,899,524 | $ | 3,761,120 | |||||
Current liabilities | $ | 189,931 | $ | 207,139 | |||||
Long-term debt | $ | 715,474 | $ | 716,359 | |||||
Other long-term liabilities | $ | 160,907 | $ | 167,545 | |||||
Deferred income taxes | $ | 753,663 | $ | 695,776 | |||||
Shareholders’ equity | $ | 2,079,549 | $ | 1,974,301 | |||||
Six Months Ended June 30, | |||||||||
2013 | 2012 | ||||||||
Statement of Cash Flows Data: | |||||||||
Cash flow from operations before changes | |||||||||
in operating assets and liabilities (1) | $ | 317,098 | $ | 345,123 | |||||
Net change in operating assets and liabilities | 790 | (30,091 | ) | ||||||
Net cash provided by operating activities | $ | 317,888 | $ | 315,032 | |||||
Net cash used in investing activities | $ | (322,471 | ) | $ | (367,608 | ) | |||
Net cash provided by financing activities |
$ |
4,650 |
$ |
52,826 |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Oil and Natural Gas Operations Data: | ||||||||||||||||
Production: | ||||||||||||||||
Oil – MBbls | 859 | 786 | 1,656 | 1,506 | ||||||||||||
Natural Gas Liquids – MBbls | 935 | 674 | 1,739 | 1,330 | ||||||||||||
Natural Gas – MMcf | 13,887 | 11,287 | 28,107 | 22,688 | ||||||||||||
Average Prices: | ||||||||||||||||
Oil price per barrel received | $ | 94.89 | $ | 92.43 | $ | 95.05 | $ | 94.04 | ||||||||
Oil price per barrel received, excluding hedges |
$ | 91.58 | $ | 89.38 | $ | 91.75 | $ | 94.53 | ||||||||
NGLs price per barrel received | $ | 30.32 | $ | 32.34 | $ | 32.47 | $ | 35.53 | ||||||||
NGLs price per barrel received, excluding hedges |
$ | 30.32 | $ | 31.12 | $ | 32.47 | $ | 34.19 | ||||||||
Natural gas price per Mcf received | $ | 3.65 | $ | 3.03 | $ | 3.47 | $ | 3.19 | ||||||||
Natural gas price per Mcf received, excluding hedges |
$ | 3.93 | $ | 1.91 | $ | 3.53 | $ | 2.18 | ||||||||
Operating profit before depreciation, depletion, amortization, and |
$ |
119.8 |
$ |
97.9 |
$ |
230.4 |
$ |
198.0 |
||||||||
Contract Drilling Operations Data: | ||||||||||||||||
Rigs utilized | 65.2 | 76.7 | 65.8 | 79.1 | ||||||||||||
Operating margins (2) | 39 | % | 49 | % | 39 | % | 48 | % | ||||||||
Operating profit before depreciation (2) ($MM) | $ | 41.4 | $ | 72.1 | $ | 82.9 | $ | 136.8 | ||||||||
Mid-Stream Operations Data: | ||||||||||||||||
Gas gathering – Mcf/day | 326,039 | 262,269 | 299,582 | 239,837 | ||||||||||||
Gas processing – Mcf/day | 138,130 | 144,257 | 134,016 | 134,744 | ||||||||||||
Liquids sold – Gallons/day | 508,189 | 629,350 | 464,483 | 576,089 | ||||||||||||
Operating profit before depreciation and amortization (2) ($MM) |
$ | 11.1 | $ | 7.4 | $ | 19.0 | $ | 17.1 |
(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, impairment, general and
administrative and gain on disposition of assets. 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, our drilling segment’s average daily
operating margin before elimination of intercompany drilling rig profit,
and net income and earnings per share excluding the effect of the
unrealized value of commodity derivatives and the impairment of oil and
natural gas properties.
Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three and six months ended June 30, 2013 and
2012. 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 |
|||||||
Six Months Ended
June 30, |
|||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Net cash provided by operating activities | $ | 317,888 | $ | 315,032 | |||
Net change in operating assets and liabilities | (790 | ) | 30,091 | ||||
Cash flow from operations before changes in operating assets and |
$ | 317,098 | $ | 345,123 |
________________
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 |
|||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||
March 31, | June 30, | June 30, | |||||||||||||
2013 | 2013 | 2012 | 2013 | 2012 | |||||||||||
(In thousands except operating days and operating margins) | |||||||||||||||
Contract drilling revenue | $ | 107,528 | $ | 105,005 | $ | 146,872 | $ | 212,533 | $ | 287,778 | |||||
Contract drilling operating cost | 66,002 | 63,590 | 74,819 | 129,592 | 150,992 | ||||||||||
Operating profit from contract drilling | 41,526 | 41,415 | 72,053 | 82,941 | 136,786 | ||||||||||
Add: | |||||||||||||||
Elimination of intercompany rig profit | 3,409 | 3,686 | 4,669 | 7,095 | 8,953 | ||||||||||
Operating profit from contract drilling before elimination of |
44,935 | 45,101 | 76,722 | 90,036 | 145,739 | ||||||||||
Contract drilling operating days | 5,964 | 5,937 | 6,893 | 11,901 | 14,224 | ||||||||||
Average daily operating margin before elimination of intercompany |
$ | 7,534 | $ | 7,597 | $ | 11,130 | $ | 7,565 | $ | 10,246 |
________________
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 Reconciliation of Net Income (Loss) and Diluted Earnings (Loss) Excluding the Effect of the Unrealized Value of Commodity And the Impairment of Oil and Natural Gas Properties |
|||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2013 | 2012 | 2013 |
|
2012 |
|||||||||||
|
|
(In thousands except earnings per share) |
|||||||||||||
Net income excluding the unrealized value of commodity derivatives |
|||||||||||||||
Net income (loss) | $ | 59,007 | $ | (19,302 | ) | $ | 99,213 | $ | 33,137 | ||||||
Impairment of oil and natural gas properties | — | 72,132 | — | 72,132 | |||||||||||
Unrealized value of commodity derivatives (net of income tax) |
(10,163 | ) | (850 | ) | (5,880 | ) | 372 | ||||||||
Net income excluding the unrealized value of commodity derivatives |
$ | 48,844 | $ | 51,980 | $ | 93,333 | $ | 105,641 | |||||||
Diluted earnings per share excluding the unrealized value of |
|||||||||||||||
Diluted earnings (loss) per share | $ | 1.22 | $ | (0.40 | ) | $ | 2.05 | $ | 0.69 | ||||||
Impairment of oil and natural gas properties | — | 1.50 | — | 1.50 | |||||||||||
Diluted earnings per share from the unrealized value of commodity |
(0.21 | ) | (0.02 | ) | (0.12 | ) | 0.01 | ||||||||
Diluted earnings per share excluding the unrealized value of |
$ | 1.01 | $ | 1.08 | $ | 1.93 | $ | 2.20 |
________________
We have included the net income excluding the unrealized value of
commodity derivatives and impairment of oil and natural gas properties
and diluted earnings per share excluding the unrealized value of
commodity derivatives and 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.
Unit Corporation
Michael D. Earl, 918-493-7700
Vice President,
Investor Relations
www.unitcorp.com
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