Continuing to Set the Stage
Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the third quarter of 2013.
Larry Pinkston, Unit’s Chief Executive Officer and President, stated,
“Unit Corporation is continuing to progress on several strategic
initiatives. We have increased the number of operated drilling rigs
drilling for our oil and natural gas segment in accordance with our
previously stated plans, and we started our pad drilling program in the
Granite Wash. In our contact drilling segment, we are nearing the
completion of the first BOSS rig which will be placed into service
during the fourth quarter, and we have completed the sale of four idle
drilling rigs during the year. Our midstream segment continues to see
the benefit of its previous capital investments with rising volumes and
cash flow growth.
“For our oil and natural gas segment, the Wilcox play has provided
consistent production growth during the year, and we are ramping up our
exploration programs in our Granite Wash and Mississippian plays. We
have initiated pad drilling in the Buffalo Wallow field which was part
of our 2012 Noble property acquisition. In the Mississippian play, we
resumed our drilling activity which had been suspended awaiting pipeline
and processing infrastructure. We entered 2013 with six operated
drilling rigs and now have 12 drilling rigs working throughout our core
plays. We anticipate seeing the initial results of this increased
activity in the fourth quarter of 2013.
“Our contract drilling segment continues to operate in a soft drilling
market. Fewer drilling rigs are drilling more wells as drilling
efficiencies are realized. Despite the soft market, we have been able to
maintain consistent utilization throughout the year. During the year, we
initiated a comprehensive evaluation of our drilling rig fleet. Part of
that evaluation included a review regarding the possible need to realign
our fleet’s capabilities and efficiencies in view of the current demand
for drilling rigs using new technologies and capabilities, a demand we
believe will continue for some time. As part of our evaluation, we
determined that we should pursue the sale of several of our older and
larger drilling rigs that have not worked for some time. Since the
beginning of the year, we have sold four of our idle 2000 horsepower
drilling rigs. Four additional idle 3000 horsepower drilling rigs are
under contract to be sold with closings anticipated to occur over the
next few months. The proceeds from these sales will be used in our new
drilling rig program, a program we launched to design and build a new
proprietary drilling rig, the BOSS rig. We anticipate this drilling rig
will position us to more effectively meet the demands of our existing
customer as well as allowing us to compete for the work of new
customers. Our first BOSS drilling rig will go to work for our oil and
natural gas segment in the fourth quarter of 2013. Our second BOSS
drilling rig is committed to an operator in North Dakota and is planned
to go into service in the second quarter of 2014. We are optimistic that
the BOSS drilling rig will continue to be well received by operators and
will result in additional new-build contract opportunities.
“Our midstream segment is seeing the benefit of our previous capital
investments in several of its projects including our Bellmon facility in
the Mississippian play in Oklahoma and our Pittsburgh Mills facility in
the Appalachian area. Downward price pressure on natural gas liquids
(NGLs) has had an impact on this segment’s cash flows. Our goal is to
position this segment for more sustainable growth with less cash flow
volatility. Where possible, we are restructuring existing commodity
price based contracts as they expire to fee based contracts. These
changes, while allowing us to remain competitive, should also reduce
this segment’s exposure to commodity price risks.”
Notable items for the quarter include:
-
Adjusted non-GAAP net income of $41.2 million, or $0.85 per diluted
share (see Non-GAAP Financial Measures below). -
Total production of 4.2 million barrels of oil equivalent (MMBoe), an
increase of 21% over the third quarter of 2012. -
Total liquids (oil and NGLs) production increased 19% over the
comparable quarter of 2012. -
Equivalent barrel realized prices decreased 9% from the second quarter
of 2013, primarily due to a 15% decrease in natural gas prices. -
Completed the sale of two 2,000 horsepower drilling rigs. After the
end of the quarter, Unit sold an additional 2,000 horsepower drilling
rig, bringing to four the number of drilling rigs sold in 2013. -
Mid-stream segment’s gathered volumes per day and liquids sold volumes
per day increased by 35% and 2%, respectively, over the third quarter
of 2012. -
Mid-stream operating profit (as defined in the Selected Financial and
Operational Highlights) was $12.7 million, an increase of 15% over the
second quarter of 2013.
Net income for the quarter was $34.2 million, or $0.70 per diluted
share, compared to $46.6 million, or $0.97 per diluted share, for the
third quarter of 2012. Adjusted net income, which excludes the effect of
non-cash settled commodity derivatives, was $41.2 million, or $0.85 per
diluted share (see Non-GAAP Financial Measures below). Total revenues
for the quarter were $333.8 million (47% oil and natural gas, 30%
contract drilling, and 23% mid-stream), compared to $321.8 million (42%
oil and natural gas, 41% contract drilling, and 17% mid-stream) for the
third quarter of 2012.
Net income for the nine months ended September 30, 2013 was $133.4
million, or $2.75 per diluted share, compared to $79.7 million, or $1.66
per diluted share, for the first nine months of 2012. Adjusted net
income for the first nine months of 2013, which excludes the effect of
non-cash settled commodity derivatives, was $134.5 million, or $2.77 per
diluted share (see Non-GAAP Financial Measures below). Total revenues
for the first nine months of 2013 were $992.7 million (48% oil and
natural gas, 32% contract drilling, and 20% mid-stream), compared to
$983.5 million (41% oil and natural gas, 43% contract drilling, and 16%
mid-stream) for the first nine months of 2012.
OIL AND NATURAL GAS SEGMENT INFORMATION
Unit’s production results reflect its focus on drilling oil or NGLs rich
wells. Liquids production represented 43% of total equivalent production
for the quarter. Total equivalent production for the quarter was 4.2
MMBoe, an increase of 21% and 3% over the third quarter of 2012 and
second quarter of 2013, respectively. Liquids production has increased
149% since the first quarter of 2009 when Unit began focusing on
increasing its liquids production. Third quarter 2013 oil production was
814,000 barrels, a decrease of 5% from both the third quarter of 2012
and second quarter of 2013. NGLs production for the quarter was
1,019,000 barrels, an increase of 49% and 9% compared to the third
quarter of 2012 and second quarter of 2013, respectively. Natural gas
production for the third quarter of 2013 was 14.3 billion cubic feet
(Bcf), an increase of 22% and 3% over the third quarter of 2012 and
second quarter of 2013, respectively. Total production for the first
nine months of 2013 was 12.3 MMBoe, an increase of 22% over the
comparable period in 2012.
Unit’s average realized per barrel equivalent price for the third
quarter of 2013 was $35.77, a decrease of 6% and 9% from the third
quarter of 2012 and second quarter of 2013, respectively. Unit’s average
natural gas price for the third quarter of 2013 was $3.11 per thousand
cubic feet (Mcf), a decrease of 9% and 15% from the third quarter of
2012 and second quarter of 2013, respectively. Unit’s average oil price
for the quarter was $95.49 per barrel, an increase of 5% and 1% over the
third quarter of 2012 and second quarter of 2013, respectively. Unit’s
average NGLs price for the quarter was $28.10 per barrel, an increase of
32% and a decrease of 7% from the third quarter of 2012 and second
quarter of 2013, respectively. For the first nine months of 2013, Unit’s
average natural gas price increased 3% to $3.35 per Mcf as compared to
$3.26 per Mcf for the first nine months of 2012. Unit’s average oil
price for the first nine months of 2013 was $95.20 per barrel compared
to $92.96 per barrel during the first nine months of 2012, a 2%
increase. Unit’s average NGLs price for the first nine months of 2013
was $30.87 per barrel compared to $30.70 per barrel during the first
nine months of 2012, a 1% increase. All prices reflected in this
paragraph include the effects of hedges. Operating costs in the third
quarter of 2013 increased 39% and 11% over the third quarter of 2012 and
second quarter of 2013, respectively. The increase over the third
quarter of 2012 was primarily due to costs associated with wells added
through acquisitions, higher salt water disposal costs, and wells
completed during 2013. The increase over the second quarter of 2013 was
primarily due to increases in both salt water disposal costs and well
servicing costs. Operating costs for the first nine months of 2013
increased 32% over the comparable period in 2012, primarily due to costs
associated with wells added through acquisitions, higher salt water
disposal costs and wells completed during 2013.
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 are hedged with swaps
and 20,000 MMBtu per day are 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 7,248 Bbls per day of its oil production and
50,000 MMBtu per day of natural gas production. Of the oil production,
3,248 Bbls per day are hedged with swaps and 4,000 Bbls per day are
hedged with collars. The swap transactions were at an average price of
$92.35. 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:
| 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | |||||||||||||||||||
|
Oil and NGL Production, MBbl |
1,832.9 |
1,794.1 |
1,600.6 |
1,694.1 |
1,545.8 |
1,460.2 |
1,375.2 |
1,359.9 |
1,197.5 |
||||||||||||||||||
| Natural Gas Production, Bcf |
14.3 |
13.9 |
14.2 |
14.5 |
11.7 |
11.3 |
11.4 |
11.4 |
11.6 |
||||||||||||||||||
| Production, MBoe |
4,217 |
4,109 |
3,971 |
4,115 |
3,498 |
3,341 |
3,275 |
3,255 |
3,123 |
||||||||||||||||||
| Production, MBoe/day |
45.8 |
45.2 |
44.1 |
44.7 |
38.0 |
36.7 |
36.0 |
35.4 |
33.9 |
||||||||||||||||||
|
Realized Price, Boe (1) |
$ |
35.77 |
$ |
39.10 |
$ |
37.99 |
$ |
39.56 |
$ |
37.99 |
$ |
38.49 |
$ |
40.51 |
$ |
42.65 |
$ |
41.75 |
|||||||||
(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
5% and 25% compared to the second quarter 2013 and the third quarter
2012, respectively. During the first three quarters of 2013, Unit
achieved a 100% success rate by completing six vertical liquids rich
Wilcox gas wells with three of the six wells located in the Gilly Field.
Unit owns 100% working interest in all six wells. Unit’s first
horizontal Wilcox well in the Gilly Field has been drilled and is
scheduled to be fracture stimulated in late November 2013. The well will
be completed from approximately 1,500 feet of Lower Wilcox lateral.
There are currently two Unit drilling rigs drilling in Unit’s Wilcox
play which should result in a total of 8 to 10 gross wells drilled in
this play during the year at a net cost of approximately $70 million.
In Unit’s Mississippian play in south central Kansas, the average daily
production for the quarter increased approximately 62% and 156% compared
to the second quarter 2013 and the third quarter 2012, respectively.
Unit resumed drilling in the prospect in late July with one Unit
drilling rig and plans to add a second Unit drilling rig late in the
fourth quarter. There were no new Mississippian completions during the
third quarter, and we expect to complete five wells during the fourth
quarter. Unit has increased its Mississippian leasehold by 13% during
the quarter to approximately 133,000 net acres and plans to spend
approximately $32 million (net) drilling and completing approximately 9
wells (100% working interest) during 2013.
In its Granite Wash (GW) play in the Texas Panhandle, average daily
production for the quarter increased approximately 6% and 46% compared
to the second quarter 2013 and the third quarter 2012, respectively. For
the first three quarters of 2013, Unit had first sales on fourteen
horizontal wells, having an average peak 30 day IP rate of 5.0 MMcfe per
day and an average working interest of 86%. Unit has completed drilling
operations on three wells located on its first pad site in the Buffalo
Wallow field targeting three different GW sands. One of the three wells
was recently fracture stimulated and in the early stages of flowing back
while the other two wells are scheduled to be completed in late
November. Two additional pad sites in the Buffalo Wallow field are
currently being drilled. Unit currently has six Unit drilling rigs
working in the GW and anticipates completing approximately 27 gross
horizontal wells during the year of which about half will be completed
in the fourth quarter.
In the Marmaton horizontal oil play in Beaver County, Oklahoma, Unit had
record average daily production of approximately 4,400 barrels of oil
equivalent per day for the quarter, an increase of approximately 16% and
21% compared to second quarter 2013 and third quarter 2012,
respectively. Unit completed 32 wells through the third quarter of 2013
with an average working interest of 76%. The average 30 day peak rate
for those wells is approximately 368 Boe. Unit has leases on
approximately 118,000 net acres in this play with approximately 55% of
the leasehold held by production. Unit anticipates continuing the two
Unit drilling rig program in this play which should result in
approximately 46 gross wells being drilled during the year for an
approximate net cost of $105 million.
Larry Pinkston said, “We are pleased with the production increase from
our oil and natural gas segment and are excited about its production
growth outlook. Production has grown during the third quarter of 2013
from the second quarter of 2013 due principally to the gradual ramp up
in company operated drilling rigs. We are now operating 12 drilling
rigs, which is an increase from 6 at the beginning of the year. We have
completed sales of certain non-core oil and natural gas assets during
2013, with total proceeds of $64.4 million.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the third quarter of 2013
was 63.5, a decrease of 13% from the third quarter of 2012, and a
decrease of 3% from the second quarter of 2013. Per day drilling rig
rates for the third quarter of 2013 averaged $19,773, a decrease of 1%,
or $216, from the third quarter of 2012, and an increase of 1% over the
second quarter of 2013. Average per day operating margin for the third
quarter of 2013 was $7,920 (before elimination of intercompany drilling
rig profit of $4.6 million). This compares to $9,672 (before elimination
of intercompany drilling rig profit of $4.0 million) for the third
quarter of 2012, a decrease of 18%, or $1,752. As compared to the second
quarter of 2013 ($7,597 before elimination of intercompany drilling rig
profit of $3.7 million), third quarter 2013 operating margin increased
4% or $323 (in each case regarding eliminating intercompany drilling rig
profit see Non-GAAP Financial Measures below). For the third quarter of
2013 average operating margins included early termination fees of
approximately $87 per day from the cancellation of certain long-term
contracts, compared to $1,007 per day for the third quarter of 2012.
For the first nine months of 2013, Unit averaged 65.0 drilling rigs
working, a decrease of 16% from 77.2 drilling rigs working during the
first nine months of 2012. Average per day operating margin for the
first nine months of 2013 was $7,682 (before elimination of intercompany
drilling rig profit of $11.7 million) as compared to $10,063 (before
elimination of intercompany drilling rig profit of $12.9 million) for
the first nine months of 2012, a decrease of 24% (in each case regarding
eliminating intercompany drilling rig profit see Non-GAAP Financial
Measures below). For the first nine months of 2013, average operating
margins included early termination fees of approximately $32 per day
from the cancellation of certain long-term contracts, compared to $1,077
per day for the first nine months of 2012.
Larry Pinkston said, “Drilling rig demand has been fairly flat during
the first nine months of 2013. Operators are continuing to focus on
shallower oil plays and liquids rich plays providing us 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.
During the third quarter, we sold two 2,000 horsepower drilling rigs.
After the end of the quarter, we sold an additional 2,000 horsepower
drilling rig, bringing our fleet’s total to 123 drilling rigs. Of the
123 drilling rigs, we have 67 under contract. Long-term contracts
(contracts with original terms ranging from six months to two years in
length) are in place for 23 of those 67 drilling rigs. Of these
contracts, six are up for renewal during the fourth quarter of 2013. We
are constructing a new prototype 1,500 horsepower AC electric drilling
rig of proprietary design. This drilling rig, called our “BOSS” rig is
expected to be operational in the fourth quarter of 2013 and will
operate initially for our oil and natural gas segment. Our second BOSS
drilling rig is committed to an operator in North Dakota and is
anticipated to be placed into service in the second quarter of 2014.”
The following table illustrates Unit’s drilling segment drilling rig
count at the end of each period and average utilization rate during the
period:
| 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | |||||||||||||||||||
| Drilling Rigs | 124 | 126 | 127 | 127 | 127 | 128 | 127 | 127 | 126 | ||||||||||||||||||
| Utilization | 51 | % | 51 | % | 52 | % | 50 | % | 58 | % | 60 | % | 64 | % | 65 | % | 63 | % | |||||||||
MID-STREAM SEGMENT INFORMATION
Third quarter of 2013 per day gathered volumes were 326,474 Mcf, an
increase of 35% over the third quarter of 2012. Per day liquids sold and
processed volumes increased 2% and 8%, respectively, as compared to the
third quarter of 2012. Compared to the second quarter of 2013, gathered
volumes per day were essentially unchanged, while liquids sold volumes
per day and processed volumes per day increased 15% and 5%,
respectively. Operating profit (as defined in the Selected Financial and
Operational Highlights) for the third quarter of 2013 was $12.7 million,
an increase of 91% over the third quarter of 2012 and an increase of 15%
over the second quarter of 2013.
The following table illustrates certain results from this segment’s
operations for the periods indicated:
| 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | 3rd Qtr 11 | ||||||||||
|
Gas gathered Mcf/day |
326,474 |
326,039 |
272,831 |
279,990 |
241,271 |
262,269 |
217,404 |
222,436 |
198,625 |
|||||||||
|
Gas processed Mcf/day |
145,020 |
138,130 |
129,857 |
131,570 |
134,907 |
144,257 |
125,231 |
126,628 |
104,351 |
|||||||||
|
Liquids sold
Gallons/day |
586,446 |
508,189 |
420,291 |
441,973 |
576,889 |
629,350 |
522,829 |
511,410 |
449,604 |
Larry Pinkston said, “In the first quarter of 2013, we completed the
installation of a second processing plant at our Bellmon facility, a 30
MMcf per day cryogenic plant. The Bellmon facility is located in the
Mississippian play in north central Oklahoma and consists of
approximately 142 miles of pipeline. Due to increasing volumes, we are
installing an additional 60 MMcf per day processing plant 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 in the
process of 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 completed initial construction of a new gathering
system and processing facility. This new system consists of
approximately 20 miles of gathering pipeline and the two processing
plants relocated from our Hemphill facility, a 5 MMcf per day
refrigeration plant and a 20 MMcf per day turbo expander plant. We began
gathering gas at this facility during the second quarter and processing
gas in the third quarter of 2013.”
FINANCIAL INFORMATION
Unit ended the third quarter with long-term debt of $645.6 million
(comprised entirely of senior subordinated notes), and a debt to
capitalization ratio of 23%. Under its credit agreement, the amount
available to be borrowed is the lesser of the amount Unit elects as the
commitment amount (currently $500 million) or the value of its borrowing
base as determined by the lenders (currently $800 million), but in
either event not to exceed $900 million. At this time, Unit has no
borrowings under its credit agreement.
MANAGEMENT COMMENT
Larry Pinkston said, “We are pleased with the performance of all three
of our segments and we are excited about their continued growth
opportunities. 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 third quarter earnings conference call live over
the Internet on November 5, 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
oil and natural gas segment, development, operational, implementation
and opportunity risks, possible delays caused by limited availability of
third party services needed in its operations, unexpected delays or
operational issues associated with the company’s new drilling rig
design, 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 | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Statement of Income: | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Oil and natural gas | $ | 157,320 | $ | 135,435 | $ | 475,728 | $ | 402,366 | ||||||||
| Contract drilling | 100,647 | 133,420 | 313,180 | 421,198 | ||||||||||||
| Gas gathering and processing | 75,809 | 52,935 | 203,821 | 159,977 | ||||||||||||
| Total revenues | 333,776 | 321,790 | 992,729 | 983,541 | ||||||||||||
| Expenses: | ||||||||||||||||
| Oil and natural gas: | ||||||||||||||||
| Operating costs | 50,139 | 36,147 | 138,171 | 105,035 | ||||||||||||
| Depreciation, depletion, and | ||||||||||||||||
| amortization | 56,294 | 44,489 | 163,612 | 153,839 | ||||||||||||
|
Impairment of oil and natural |
||||||||||||||||
| gas properties | — | — | — | 115,874 | ||||||||||||
| Contract drilling: | ||||||||||||||||
| Operating costs | 58,988 | 72,988 | 188,580 | 223,980 | ||||||||||||
| Depreciation | 17,402 | 20,094 | 52,570 | 62,660 | ||||||||||||
| Gas gathering and processing: | ||||||||||||||||
| Operating costs | 63,098 | 46,267 | 172,065 | 136,243 | ||||||||||||
| Depreciation and amortization | 8,773 | 5,884 | 24,143 | 16,330 | ||||||||||||
| General and administrative | 9,936 | 8,434 | 28,288 | 23,814 | ||||||||||||
| Gain on disposition of assets | (4,345 | ) | (44 | ) | (7,744 | ) | (1,283 | ) | ||||||||
| Total operating expenses | 260,285 | 234,259 | 759,685 | 836,492 | ||||||||||||
| Income from operations | 73,491 | 87,531 | 233,044 | 147,049 | ||||||||||||
| Other income (expense): | ||||||||||||||||
| Interest, net | (3,625 | ) | (7,087 | ) | (11,777 | ) | (11,455 | ) | ||||||||
| Loss on derivatives not | ||||||||||||||||
|
designated as hedges and hedge ineffectiveness, net |
(13,760 |
) |
(4,015 |
) |
(3,340 |
) |
(4,621 |
) |
||||||||
| Other | (14 | ) | (59 | ) | (171 | ) | (123 | ) | ||||||||
| Total other income (expense) | (17,399 | ) | (11,161 | ) | (15,288 | ) | (16,199 | ) | ||||||||
| Income before income taxes | 56,092 | 76,370 | 217,756 | 130,850 | ||||||||||||
| Income tax expense: | ||||||||||||||||
| Current | 2,111 | 2,516 | 6,745 | 450 | ||||||||||||
| Deferred | 19,749 | 27,268 | 77,566 | 50,677 | ||||||||||||
| Total income taxes | 21,860 | 29,784 | 84,311 | 51,127 | ||||||||||||
| Net income | $ | 34,232 | $ | 46,586 | $ | 133,445 | $ | 79,723 | ||||||||
| Net income per common share: | ||||||||||||||||
| Basic | $ | 0.71 | $ | 0.97 | $ | 2.77 | $ | 1.66 | ||||||||
| Diluted | $ | 0.70 | $ | 0.97 | $ | 2.75 | $ | 1.66 | ||||||||
| Weighted average shares outstanding: | ||||||||||||||||
| Basic | 48,254 | 47,938 | 48,193 | 47,891 | ||||||||||||
| Diluted | 48,658 | 48,201 | 48,510 | 48,106 | ||||||||||||
| September 30, | December 31, | |||||
| 2013 | 2012 | |||||
| Balance Sheet Data: | ||||||
| Current assets | $ | 181,575 | $ | 195,644 | ||
| Total assets | $ | 3,924,695 | $ | 3,761,120 | ||
| Current liabilities | $ | 229,655 | $ | 207,139 | ||
| Long-term debt | $ | 645,584 | $ | 716,359 | ||
| Other long-term liabilities | $ | 159,099 | $ | 167,545 | ||
| Deferred income taxes | $ | 773,412 | $ | 695,776 | ||
| Shareholders’ equity | $ | 2,116,945 | $ | 1,974,301 | ||
| Nine Months Ended September 30, | ||||||||
| 2013 | 2012 | |||||||
| Statement of Cash Flows Data: | ||||||||
| Cash flow from operations before changes | ||||||||
| in operating assets and liabilities (1) | $ | 468,537 | $ | 499,609 | ||||
| Net change in operating assets and liabilities | 32,424 | 12,531 | ||||||
| Net cash provided by operating activities | $ | 500,961 | $ | 512,140 | ||||
| Net cash used in investing activities | $ | (422,658 | ) | $ | (888,597 | ) | ||
| Net cash provided by (used in) | ||||||||
| financing activities | $ | (77,536 | ) | $ | 376,645 | |||
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Oil and Natural Gas Operations Data: | ||||||||||||||||
| Production: | ||||||||||||||||
| Oil – MBbls | 814 | 861 | 2,470 | 2,367 | ||||||||||||
| Natural Gas Liquids – MBbls | 1,019 | 684 | 2,758 | 2,014 | ||||||||||||
| Natural Gas – MMcf | 14,304 | 11,716 | 42,411 | 34,403 | ||||||||||||
| Average Prices: | ||||||||||||||||
|
Oil price per barrel received |
$ | 95.49 | $ | 91.07 | $ | 95.20 | $ | 92.96 | ||||||||
|
Oil price per barrel received, excluding hedges |
$ | 103.09 | $ | 87.38 | $ | 95.49 | $ | 91.93 | ||||||||
| NGLs price per barrel received | $ | 28.10 | $ | 21.34 | $ | 30.87 | $ | 30.70 | ||||||||
| NGLs price per barrel received, | ||||||||||||||||
| excluding hedges | $ | 28.10 | $ | 20.75 | $ | 30.87 | $ | 29.61 | ||||||||
| Natural gas price per Mcf received | $ | 3.11 | $ | 3.40 | $ | 3.35 | $ | 3.26 | ||||||||
| Natural gas price per Mcf received, | ||||||||||||||||
| excluding hedges | $ | 3.07 | $ | 2.50 | $ | 3.38 | $ | 2.29 | ||||||||
|
Operating profit before depreciation, depletion, |
||||||||||||||||
| amortization, and impairment (2) ($MM) | $ | 107.2 | $ | 99.3 | $ | 337.6 | $ | 297.3 | ||||||||
| Contract Drilling Operations Data: | ||||||||||||||||
| Rigs utilized | 63.5 | 73.4 | 65.0 | 77.2 | ||||||||||||
| Operating margins (2) | 41 | % | 45 | % | 40 | % | 47 | % | ||||||||
| Operating profit before depreciation (2) ($MM) | $ | 41.7 | $ | 60.4 | $ | 124.6 | $ | 197.2 | ||||||||
| Mid-Stream Operations Data: | ||||||||||||||||
| Gas gathering – Mcf/day | 326,474 | 241,271 | 308,645 | 240,318 | ||||||||||||
| Gas processing – Mcf/day | 145,020 | 134,907 | 137,725 | 134,799 | ||||||||||||
| Liquids sold – Gallons/day | 586,446 | 576,889 | 505,584 | 576,358 | ||||||||||||
| Operating profit before depreciation | ||||||||||||||||
| and amortization (2) ($MM) | $ | 12.7 | $ | 6.7 | $ | 31.8 | $ | 23.7 | ||||||||
(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, 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 including only the effect of the
cash settled commodity derivatives and excluding 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 nine months ended September 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 Operating Assets and Liabilities |
||||||||
|
|
||||||||
| Nine Months Ended | ||||||||
| June 30, | ||||||||
| 2013 | 2012 | |||||||
| (In thousands) | ||||||||
| Net cash provided by operating activities | $ | 500,961 | $ | 512,140 | ||||
| Net change in operating assets and liabilities | (32,424 | ) | (12,531 | ) | ||||
| Cash flow from operations before changes | ||||||||
| in operating assets and liabilities | $ | 468,537 | $ | 499,609 | ||||
________________
We have included the cash flow from operations before changes in
operating assets and liabilities because:
-
It is an accepted financial indicator used by our management and
companies in our industry to measure the company’s ability to generate
cash which is used to internally fund our business activities. -
It is used by investors and financial analysts to evaluate the
performance of our company.
| Unit Corporation | |||||||||||||||
| Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit |
|||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||
| June 30, | September 30, | September 30, | |||||||||||||
| 2013 | 2013 | 2012 | 2013 | 2012 | |||||||||||
| (In thousands except operating days and operating margins) | |||||||||||||||
| Contract drilling revenue | $ | 105,005 | $ | 100,647 | $ | 133,420 | $ | 313,180 | $ | 421,198 | |||||
| Contract drilling operating cost | 63,590 | 58,988 | 72,988 | 188,580 | 223,980 | ||||||||||
| Operating profit from contract drilling | 41,415 | 41,659 | 60,432 | 124,600 | 197,218 | ||||||||||
|
Add:
Elimination of intercompany rig profit |
3,686 |
4,579 |
3,983 |
11,674 |
12,936 |
||||||||||
| Operating profit from contract drilling | |||||||||||||||
| before elimination of intercompany | |||||||||||||||
| rig profit | 45,101 | 46,238 | 64,415 | 136,274 | 210,154 | ||||||||||
| Contract drilling operating days | 5,937 | 5,838 | 6,660 | 17,739 | 20,884 | ||||||||||
| Average daily operating margin before | |||||||||||||||
| elimination of intercompany rig profit | $ | 7,597 | $ | 7,920 | $ | 9,672 | $ | 7,682 | $ | 10,063 | |||||
________________
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 Adjusted Net Income and Adjusted Diluted Earnings per Share |
||||||||||||||
| Three Months Ended | Nine Months Ended | |||||||||||||
| September 30, | September 30, | |||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||
|
|
(In thousands except per share amounts) |
|||||||||||||
| Adjusted net income: | ||||||||||||||
| Net income | $ | 34,232 | $ | 46,586 | $ | 133,445 | $ | 79,723 | ||||||
| Impairment of oil and natural gas properties | — | — | — | 72,132 | ||||||||||
| Loss on derivatives not designated as hedges and | ||||||||||||||
| hedge ineffectiveness (net of income tax) | 8,455 | 2,449 | 2,047 | 2,821 | ||||||||||
| Settlements during the period of matured | ||||||||||||||
| derivative contracts (net of income tax) | (1,493 | ) | — | (965 | ) | — | ||||||||
| Adjusted net income | $ | 41,194 | $ | 49,035 | $ | 134,527 | $ | 154,676 | ||||||
| Adjusted diluted earnings per share: | ||||||||||||||
| Diluted earnings per share | $ | 0.70 | $ | 0.97 | $ | 2.75 | $ | 1.66 | ||||||
| Impairment of oil and natural gas properties | — | — | — | 1.50 | ||||||||||
| Diluted earnings per share from the (gain) loss | ||||||||||||||
| on derivatives | 0.18 | 0.05 | 0.04 | 0.06 | ||||||||||
| Diluted earnings per share from the settlements | ||||||||||||||
| of matured derivative contracts | (0.03 | ) | — | (0.02 | ) | — | ||||||||
| Adjusted diluted earnings per share | $ | 0.85 | $ | 1.02 | $ | 2.77 | $ | 3.22 | ||||||
________________
We have included the net income and diluted earnings per share excluding
the impairment of oil and natural gas properties and including only the
cash settled commodity derivatives 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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