Unit Corporation (NYSE:UNT) today reported its financial and operational
results for the fourth quarter and year 2013.
Larry Pinkston, Unit’s Chief Executive Officer and President, stated
“During 2013, the company continued to progress on several strategic
initiatives. Our production in the fourth quarter increased 5% over the
third quarter and overall production increased 18% year over year.
Throughout the fourth quarter we increased the number of operated
drilling rigs drilling for our oil and natural gas segment under our
previously stated plans, and we initiated our pad drilling program in
the Granite Wash. In our contract drilling segment, we completed the
sale of five idle drilling rigs during the year, and we will place our
first BOSS rig into service during the first quarter 2014. Our midstream
segment continued to see the benefit of previous capital investments.
“For the oil and natural gas segment, we are very pleased with our
fourth quarter production growth. For the full year, we achieved the
upper end of our production guidance. Fourth quarter production growth
was primarily driven by the Wilcox and Granite Wash plays. During 2013,
we completed sales of certain non-core oil and natural gas assets, with
total proceeds of $78.8 million with the most significant portion coming
from the sale of the majority of our non-operated Bakken assets. We
ended 2013 with total proved reserves of 160 million barrels of oil
equivalent (MMBoe), a 7% increase, despite the sale of non-core
properties with total proved reserves of 3.5 MMBoe. Weather and
operational delays will affect first quarter 2014 production; however,
we continue to anticipate production growth for 2014 of between 15% and
18%.
“Our contract drilling segment operated in a soft drilling market
throughout 2013; however, we were able to maintain fairly consistent
utilization. During the fourth quarter of 2013 we averaged 65 drilling
rigs operating. We have seen improvement in utilization in the first
quarter of 2014. Currently, we have 69 drilling rigs operating with
continued improvement expected through the end of the first quarter. We
also initiated a comprehensive evaluation of our drilling rig fleet that
included a review regarding the possible realignment of our fleet’s
capabilities and efficiencies. In view of the demand for drilling rigs
using new technologies and capabilities, we determined we should pursue
the sale of several of our older and larger drilling rigs that have not
worked for some time. As a result, during 2013, we sold four of our idle
2,000 horsepower drilling rigs and one 3,000 horsepower drilling rig
with proceeds totaling $32.4 million. In addition, the sale of four
additional idle 3,000 horsepower drilling rigs was completed after year
end. 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, coupled
with continued enhancements to our existing fleet, will position us to
continue to meet the demands of our existing customers and allow us to
compete for the work of new customers. Our first BOSS drilling rig will
work for our oil and natural gas segment during the first quarter of
2014. We are optimistic that the BOSS drilling rig will be well received
by operators and will result in additional new-build contract
opportunities.
“The midstream segment is experiencing the benefit of previous capital
investments in several of our projects including the Bellmon facility in
the Mississippian play in Oklahoma and the Pittsburgh Mills facility in
the Appalachian area. Downward price pressure on natural gas liquids
(NGLs) during 2012 impacted this segment’s cash flows. Due to the
increase in liquids pricing in the first quarter of 2014, particularly
propane, we are now operating in full ethane recovery mode at all of our
processing facilities. 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 reduce this segment’s exposure to commodity
price risks.”
Notable items for the company for the quarter include:
-
Adjusted non-GAAP net income of $54.3 million, or $1.11 per diluted
share (see Non-GAAP Financial Measures below). -
Total production of 4.4 MMBoe, an increase of 8% over the fourth
quarter of 2012. -
Total liquids (oil and NGLs) production increased 21% over the
comparable quarter of 2012. -
Completed the sale of a 2,000 horsepower drilling rig and a 3,000
horsepower drilling rig, bringing to five the number of drilling rigs
sold in 2013. -
Mid-stream segment’s gathered volumes per day, processed volumes per
day and liquids sold volumes per day increased by 12%, 13% and 49%,
respectively, over the fourth quarter of 2012.
Net income for the quarter was $51.3 million, or $1.05 per diluted
share, compared to a loss of $56.5 million, or $1.18 per diluted share,
for the fourth quarter of 2012. Adjusted net income, which excludes the
effect of non-cash commodity derivatives, was $54.3 million, or $1.11
per diluted share (see Non-GAAP Financial Measures below). Total
revenues for the quarter were $359.1 million (49% oil and natural gas,
28% contract drilling, and 23% mid-stream), compared to $331.6 million
(50% oil and natural gas, 33% contract drilling, and 17% mid-stream) for
the fourth quarter of 2012.
Net income for 2013 was $184.7 million, or $3.80 per diluted share,
compared to $23.2 million, or $0.48 per diluted share, for 2012.
Adjusted net income for 2013, which excludes the effect of non-cash
commodity derivatives, was $188.8 million, or $3.89 per diluted share
(see Non-GAAP Financial Measures below). Total revenues for 2013 were
$1.35 billion (48% oil and natural gas, 31% contract drilling, and 21%
mid-stream), compared to $1.32 billion (43% oil and natural gas, 40%
contract drilling, and 17% mid-stream) for 2012.
OIL AND NATURAL GAS SEGMENT INFORMATION
Unit’s production results reflect its focus on drilling oil or NGLs rich
wells. Liquids production represented 46% of total equivalent production
for the quarter. Total equivalent production for the quarter was 4.4
MMBoe, an increase of 8% and 5% over the fourth quarter of 2012 and
third quarter of 2013, respectively. Liquids production has increased
178% since the first quarter of 2009 when Unit began to focus on
increasing liquids production. Fourth quarter 2013 oil production was
891,000 barrels, a decrease of 2% from the fourth quarter of 2012 and an
increase of 9% over the third quarter of 2013. NGLs production for the
quarter was 1,156,000 barrels, an increase of 48% and 14% compared to
the fourth quarter of 2012 and third quarter of 2013, respectively.
Natural gas production for the fourth quarter of 2013 was 14.3 billion
cubic feet (Bcf), a decrease of 1% from the fourth quarter of 2012 and
relatively flat with the third quarter of 2013. Total production for
2013 was 16.7 MMBoe, an increase of 18% over 2012.
Unit’s average realized per barrel equivalent price for the fourth
quarter of 2013 was $38.24, a decrease of 3% from the fourth quarter of
2012 and an increase of 7% over the third quarter of 2013. Unit’s
average natural gas price for the fourth quarter of 2013 was $3.21 per
thousand cubic feet (Mcf), a decrease of 12% from the fourth quarter of
2012 and a 3% increase over the third quarter of 2013. Unit’s average
oil price for the quarter was $94.70 per barrel, an increase of 3% over
the fourth quarter of 2012 and a decrease of 1% from the third quarter
of 2013. Unit’s average NGLs price for the quarter was $33.94 per
barrel, which was essentially unchanged from the fourth quarter of 2012
and an increase of 21% over the third quarter of 2013. For 2013, Unit’s
average natural gas price decreased 1% to $3.32 per Mcf as compared to
$3.37 per Mcf for 2012. Unit’s average oil price for 2013 was $95.06 per
barrel compared to $92.60 per barrel during 2012, a 3% increase. Unit’s
average NGLs price for 2013 was $31.79 per barrel compared to $31.58 per
barrel during 2012, a 1% increase. All prices in this paragraph include
the effects of hedges.
For 2013, Unit hedged 8,330 Bbls per day of its oil production and
100,000 MMBtu per day of natural gas production. The oil production was
hedged under swap contracts at an average price of $97.94 per barrel. Of
the natural gas production, 80,000 MMBtu per day were hedged with swaps
and 20,000 MMBtu per day 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 7,250 Bbls per day of its oil production and
90,000 MMBtu per day of natural gas production. Of the oil production,
3,250 Bbls per day are hedged with swaps and 4,000 Bbls per day are
hedged with collars. The swap transactions have an average price of
$92.35. The collar transactions have an average floor price of $90.00
and ceiling price of $96.08. Of the natural gas production, 80,000 MMBtu
per day are hedged with swaps and 10,000 MMBtu per day are hedged with
collars. The swap transactions are at a comparable average NYMEX price
of $4.24. The collar transactions have a comparable average NYMEX floor
price of $3.75 and ceiling price of $4.37.
The following table illustrates Unit’s production and realized prices
for the periods indicated:
| 4th Qtr 13 | 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | |||||||||||||||||||||||||||||
|
Oil and NGL Production, MBbl |
2,046.7 |
1,832.9 |
1,794.1 |
1,600.6 |
1,694.1 |
1,545.8 |
1,460.2 |
1,375.2 |
1,359.9 |
||||||||||||||||||||||||||||
| Natural Gas Production, Bcf |
14.3 |
14.3 |
13.9 |
14.2 |
14.5 |
11.7 |
11.3 |
11.4 |
11.4 |
||||||||||||||||||||||||||||
| Production, MBoe |
4,438 |
4,217 |
4,109 |
3,971 |
4,115 |
3,498 |
3,341 |
3,275 |
3,255 |
||||||||||||||||||||||||||||
| Production, MBoe/day |
48.2 |
45.8 |
45.2 |
44.1 |
44.7 |
38.0 |
36.7 |
36.0 |
35.4 |
||||||||||||||||||||||||||||
|
Realized Price, Boe (1) |
$ |
38.24 |
$ |
35.77 |
$ |
39.10 |
$ |
37.99 |
$ |
39.56 |
$ |
37.99 |
$ |
38.49 |
$ |
40.51 |
$ |
42.65 |
|||||||||||||||||||
|
(1) Realized price includes oil, natural gas liquids, natural gas |
|||||||||||||||||||||||||||||||||||||
The Wilcox play in southeast Texas continues to deliver strong results
with average daily production for the fourth quarter of 2013 increasing
approximately 12% and 45% compared to the third quarter 2013 and the
fourth quarter 2012, respectively. Production for 2013 increased 21% as
compared to 2012. For 2013, Unit completed six vertical and one
horizontal liquids rich Wilcox gas wells and drilled one dry hole. Unit
owns 100% working interest in all eight wells. Unit’s first horizontal
Wilcox well was completed in late November 2013 at an initial rate of
approximately 4.4 MMcf per day and 73 barrels of condensate per day from
approximately 1,500 feet of Basal Wilcox lateral. The initial results
are encouraging, but additional production data is needed to better
estimate the ultimate reserves of this well. There are currently two
Unit rigs drilling in Unit’s Wilcox play with plans to add a third rig
in the second half of the year, which should result in approximately 10
to 12 vertical wells and two to four horizontal wells drilled in this
play in 2014.
In the Texas Panhandle District, which consists primarily of Granite
Wash (GW) wells and to a lesser degree Cleveland wells, the average
daily production for the fourth quarter of 2013 increased approximately
13% and 17% compared to the third quarter 2013 and the fourth quarter
2012, respectively. For 2013, production increased approximately 28%
over 2012. Unit had first sales on 23 horizontal GW wells, having an
average peak 30 day IP rate of 5.2 MMcfe per day and an average working
interest of 85%. Unit also had first sales on three Cleveland wells with
an average peak 30 day rate of 3.9 MMcfe per day at an average working
interest of 80%. Unit recently completed drilling operations on three
separate well pads located in different sections of the Buffalo Wallow
GW field. Each pad has three wells resulting in nine total wells that
will target five different GW sand intervals. Six of the wells have been
fracture stimulated and the remaining three wells are scheduled to be
fracture stimulated in the first quarter 2014. Unit plans to monitor
production from these three pads for approximately 90 days prior to
resuming pad drilling in the field. At the conclusion of the testing
phase, the company will report the results from all nine wells. Unit
plans to run three to five Unit rigs in the GW play and one Unit rig in
the Cleveland play during 2014.
In Unit’s Mississippian play in south central Kansas, the average daily
production for the fourth quarter of 2013 increased approximately 47%
compared to the third quarter 2013. For 2013, production increased 218%
as compared to 2012. Unit had first sales on eight Mississippian wells
during 2013 with an average 30 day IP rate of 222 Boe per day consisting
of an average of approximately 53% oil, 11% NGLs, and 36% natural gas
with a 100% average working interest. The last four wells completed in
the fourth quarter of 2013 had a significantly higher liquids cut
consisting of approximately 79% oil, 6% NGLs, and 15% natural gas with
an average 30 day IP rate of approximately 231 Boe per day. The company
is currently considering altering its drilling program in this play in
2014 to drill extended lateral wells and to test different fracture
stimulation designs. Unit is currently running two Unit rigs in the play.
In the Marmaton horizontal oil play in Beaver County, Oklahoma, Unit had
first sales on 41 horizontal wells during 2013 with an average 30 day IP
rate of 371 Boe per day with an approximate average working interest of
75%. The average daily production for the fourth quarter of 2013 was
essentially unchanged from the third quarter 2013 but increased
approximately 25% for the year as compared to 2012. Two additional
potential horizontal targets in the play are scheduled to be tested in
early 2014. Unit had two Unit rigs drilling in the play and plans to
continue with this two rig drilling program.
YEAR END 2013 ESTIMATED PROVED RESERVES
The value of Unit’s estimated year-end 2013 proved reserves increased by
21% to $1.8 billion year over year. Unit’s estimated year-end 2013
proved oil and natural gas reserves were 160 MMBoe, or 960 billion cubic
feet of natural gas equivalents (Bcfe), as compared with 150 MMBoe, or
899 Bcfe, at year-end 2012, a 7% increase in its estimated proved
reserves. From all sources, Unit replaced approximately 161% of its 2013
production. Estimated reserves were 13% oil, 26% NGLs, and 61% natural
gas. During 2013, Unit divested 3.5 MMBoe of non-core oil and natural
gas reserves.
The following details the changes to Unit’s proved oil, NGLs, and
natural gas reserves during 2013:
|
Oil |
NGLs |
Natural Gas |
Proved |
||||||||||||||
| Proved Reserves, at December 31, 2012 | 22.0 | 35.2 | 555.6 | 149.8 | |||||||||||||
| Revisions of previous estimates | (2.1 | ) | 0.8 | 2.4 | (0.9 | ) | |||||||||||
|
Extensions, discoveries, and other additions |
7.0 |
9.2 |
90.2 |
31.2 |
|||||||||||||
| Purchases of minerals in place | — | — | — | — | |||||||||||||
| Production | (3.4 | ) | (3.9 | ) | (56.7 | ) | (16.7 | ) | |||||||||
| Sales | (1.7 | ) | (0.1 | ) | (9.7 | ) | (3.5 | ) | |||||||||
| Proved Reserves, at December 31, 2013 | 21.8 | 41.2 | 581.8 | 159.9 | |||||||||||||
The estimated 2013 year-end proved reserves included proved developed
reserves of 123 MMBoe, or 740 Bcfe, (split 13% oil, 24% NGLs, and 63%
natural gas) and proved undeveloped reserves of 37 MMBoe, or 219 Bcfe,
(split 17% oil, 29% NGLs, and 54% natural gas). Overall, 77% of Unit’s
estimated proved reserves are proved developed.
The present value of the estimated future net cash flows from the 2013
estimated proved reserves (before income taxes and using a 10% discount
rate (PV-10)), was approximately $1.8 billion. The present value was
determined using the 12 month 2013 average price received. The aggregate
price used for all future reserves was $94.76 per barrel of oil, $34.61
per barrel of NGLs, and $3.58 per Mcf of natural gas. Unit’s 2013
year-end proved reserves were independently audited by Ryder Scott
Company, L.P. Their audit covered properties which accounted for 84% of
the discounted future net cash flow (PV-10). See below for the
reconciliation of PV-10 to the standardized measure of discounted future
net cash flows as defined by GAAP.
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the fourth quarter of 2013
was 65.0, an increase of 2% over both the fourth quarter of 2012 and the
third quarter of 2013. Per day drilling rig rates for the fourth quarter
of 2013 averaged $19,630, a decrease of 1% from the fourth quarter of
2012 and the third quarter of 2013. Average per day operating margin for
the fourth quarter of 2013 was $8,132 (before elimination of
intercompany drilling rig profit of $5.7 million). This compares to
$7,838 (before elimination of intercompany drilling rig profit of $2.6
million) for the fourth quarter of 2012, an increase of 4%, or $294. As
compared to the third quarter of 2013 ($7,920 before elimination of
intercompany drilling rig profit of $4.6 million), fourth quarter 2013
operating margin increased 3% or $212 (in each case regarding
eliminating intercompany drilling rig profit see Non-GAAP Financial
Measures below). For the fourth quarter of 2013 average operating
margins included early termination fees of approximately $161 per day
from the cancellation of certain long-term contracts, compared to $23
per day for the fourth quarter of 2012.
For 2013, Unit averaged 65.0 drilling rigs working, a decrease of 12%
from 73.9 drilling rigs working during 2012. Average per day operating
margin for 2013 was $7,796 (before elimination of intercompany drilling
rig profit of $17.4 million) as compared to $9,578 (before elimination
of intercompany drilling rig profit of $15.6 million) for 2012, a
decrease of 19% (in each case regarding eliminating intercompany
drilling rig profit see Non-GAAP Financial Measures below). For 2013,
average operating margins included early termination fees of
approximately $80 per day from the cancellation of certain long-term
contracts, compared to $847 per day for 2012.
Larry Pinkston said: “Drilling rig demand was fairly flat during 2013.
Almost all of our drilling rigs working today are drilling for oil or
NGLs. During the year, we sold four 2,000 horsepower drilling rigs, one
3,000 horsepower drilling rig, and retired one 700 horsepower drilling
rig, bringing our fleet’s total to 121 drilling rigs at year end.
Subsequent to year end, we sold four additional idle 3,000 horsepower
drilling rigs, bringing our current fleet’s total to 117 drilling rigs.
Of the 117 drilling rigs, we have 69 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 69 drilling rigs. Of these
contracts, seven are up for renewal during the first quarter of 2014,
ten in the second quarter, five in the fourth quarter, and one is up for
renewal in 2015. We are constructing a new prototype 1,500 horsepower AC
electric drilling rig of proprietary design. This drilling rig, called
our “BOSS” rig, will be operational in the first quarter of 2014 and
will operate initially for our oil and natural gas segment. Two
additional BOSS drilling rigs are contracted to third party operators
and are anticipated to be placed into service in the second and third
quarters 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:
| 4th Qtr 13 | 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | |||||||||||||||||||||||||||||
| Drilling Rigs | 121 | 124 | 126 | 127 | 127 | 127 | 128 | 127 | 127 | ||||||||||||||||||||||||||||
| Utilization | 53 | % | 51 | % | 51 | % | 52 | % | 50 | % | 58 | % | 60 | % | 64 | % | 65 | % | |||||||||||||||||||
MID-STREAM SEGMENT INFORMATION
Fourth quarter of 2013 per day gathered volumes were 312,254 Mcf, an
increase of 12% over the fourth quarter of 2012. Per day liquids sold
and processed volumes increased 49% and 13%, respectively, as compared
to the fourth quarter of 2012. Compared to the third quarter of 2013,
gathered volumes per day decreased 4%, while liquids sold volumes per
day and processed volumes per day increased 12% and 3%, respectively.
Operating profit (as defined in the Selected Financial and Operational
Highlights) for the fourth quarter of 2013 was $12.2 million, an
increase of 89% over the fourth quarter of 2012 and a decrease of 4%
from the third quarter of 2013. The decrease in operating profit during
the fourth quarter was primarily due to an increase in operating
expenses relating to cold weather.
The following table illustrates certain results from this segment’s
operations for the periods indicated:
| 4th Qtr 13 | 3rd Qtr 13 | 2nd Qtr 13 | 1st Qtr 13 | 4th Qtr 12 | 3rd Qtr 12 | 2nd Qtr 12 | 1st Qtr 12 | 4th Qtr 11 | ||||||||||||||||||||
|
Gas gathered Mcf/day |
312,254 |
326,474 |
326,039 |
272,831 |
279,990 |
241,271 |
262,269 |
217,404 |
222,436 |
|||||||||||||||||||
|
Gas processed Mcf/day |
149,069 |
145,020 |
138,130 |
129,857 |
131,570 |
134,907 |
144,257 |
125,231 |
126,628 |
|||||||||||||||||||
|
Liquids sold |
656,415 |
586,446 |
508,189 |
420,291 |
441,973 |
576,889 |
629,350 |
522,829 |
511,410 |
|||||||||||||||||||
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 in the
Mississippian play in north central Oklahoma and comprises approximately
185 miles of pipeline. Due to increasing volumes, we installed an
additional 60 MMcf per day processing plant which became fully
operational in February 2014. 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. In the fourth
quarter of 2013, we completed 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 comprises
approximately 20 miles of gathering pipeline and the two processing
plants relocated from our Hemphill facility, a 5 MMcf per day
refrigerated JT 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 year with long-term debt of $645.7 million (comprising
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. Unit currently 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 are excited about their continued growth
opportunities. Each segment is operating under key initiatives intended
to create additional shareholder value for years to come. We continue to
maintain a conservative financial profile. We are well positioned for
sustained growth and to take advantage of new opportunities that may
arise.”
WEBCAST
Unit will webcast its fourth quarter and year-end earnings conference
call live over the Internet on February 25, 2014 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 | Twelve Months Ended | |||||||||||||||||
| December 31, | December 31, | |||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||||
| Statement of Income: | ||||||||||||||||||
| Revenues: | ||||||||||||||||||
| Oil and natural gas | $ | 173,990 | $ | 165,578 | $ | 649,718 | $ | 567,944 | ||||||||||
| Contract drilling | 101,598 | 108,521 | 414,778 | 529,719 | ||||||||||||||
| Gas gathering and processing | 83,533 | 57,483 | 287,354 | 217,460 | ||||||||||||||
| Total revenues | 359,121 | 331,582 | 1,351,850 | 1,315,123 | ||||||||||||||
| Expenses: | ||||||||||||||||||
| Oil and natural gas: | ||||||||||||||||||
| Operating costs | 45,830 | 45,177 | 184,001 | 150,212 | ||||||||||||||
|
Depreciation, depletion, and amortization |
62,886 | 57,508 | 226,498 | 211,347 | ||||||||||||||
|
Impairment of oil and natural gas properties |
— |
167,732 | — | 283,606 | ||||||||||||||
| Contract drilling: | ||||||||||||||||||
| Operating costs | 58,700 | 65,544 | 247,280 | 289,524 | ||||||||||||||
| Depreciation | 18,624 | 18,347 | 71,194 | 81,007 | ||||||||||||||
| Gas gathering and processing: | ||||||||||||||||||
| Operating costs | 71,341 | 51,049 | 243,406 | 187,292 | ||||||||||||||
|
Depreciation and amortization |
9,048 | 8,058 | 33,191 | 24,388 | ||||||||||||||
| General and administrative | 10,035 | 9,272 | 38,323 | 33,086 | ||||||||||||||
| Gain on disposition of assets | (9,332 | ) | 1,030 | (17,076 | ) | (253 | ) | |||||||||||
| Total expenses | 267,132 | 423,717 | 1,026,817 | 1,260,209 | ||||||||||||||
| Income (loss) from operations | 91,989 | (92,135 | ) | 325,033 | 54,914 | |||||||||||||
| Other income (expense): | ||||||||||||||||||
| Interest, net | (3,238 | ) | (2,682 | ) | (15,015 | ) | (14,137 | ) | ||||||||||
|
Gain (loss) on derivatives not designated as hedges and hedge |
(5,034 |
) |
3,378 |
(8,374 |
) |
(1,243 |
) |
|||||||||||
| Other | (4 | ) | (9 | ) | (175 | ) | (132 | ) | ||||||||||
|
Total other income (expense) |
(8,276 | ) | 687 | (23,564 | ) | (15,512 | ) | |||||||||||
| Income (loss) before income taxes | 83,713 | (91,448 | ) | 301,469 | 39,402 | |||||||||||||
| Income tax expense (benefit): | ||||||||||||||||||
| Current | 9,246 | 246 | 15,991 | 696 | ||||||||||||||
| Deferred | 23,166 | (35,147 | ) | 100,732 | 15,530 | |||||||||||||
| Total income taxes | 32,412 | (34,901 | ) | 116,723 | 16,226 | |||||||||||||
| Net income (loss) | $ | 51,301 | $ | (56,547 | ) | $ | 184,746 | $ | 23,176 | |||||||||
| Net income (loss) per common share: | ||||||||||||||||||
| Basic | $ | 1.06 | $ | (1.18 | ) | $ | 3.83 | $ | 0.48 | |||||||||
| Diluted | $ | 1.05 | $ | (1.18 | ) | $ | 3.80 | $ | 0.48 | |||||||||
| Weighted average shares outstanding: | ||||||||||||||||||
| Basic | 48,292 | 47,960 | 48,218 | 47,909 | ||||||||||||||
| Diluted | 48,795 | 47,960 | 48,572 | 48,154 | ||||||||||||||
|
|
December 31, | December 31, | ||||||
| 2013 | 2012 | |||||||
| Balance Sheet Data: | ||||||||
| Current assets | $ | 212,031 | $ | 195,644 | ||||
| Total assets | $ | 4,022,390 | $ | 3,761,120 | ||||
| Current liabilities | $ | 243,573 | $ | 207,139 | ||||
| Long-term debt | $ | 645,696 | $ | 716,359 | ||||
| Other long-term liabilities | $ | 158,331 | $ | 167,545 | ||||
| Deferred income taxes | $ | 801,398 | $ | 695,776 | ||||
| Shareholders’ equity |
$ |
2,173,392 | $ | 1,974,301 | ||||
| Twelve Months Ended December 31, | ||||||||||
| 2013 | 2012 | |||||||||
| Statement of Cash Flows Data: | ||||||||||
|
Cash flow from operations before changes in operating assets and |
$ | 637,936 | $ | 664,765 | ||||||
|
Net change in operating assets and liabilities |
36,395 | 26,146 | ||||||||
|
Net cash provided by operating activities |
$ | 674,331 | $ | 690,911 | ||||||
|
Net cash used in investing activities |
$ | (579,180 | ) | $ | (1,079,042 | ) | ||||
|
Net cash provided by (used in) financing activities |
$ |
(77,532 | ) |
$ |
388,270 | |||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
| Oil and Natural Gas Operations Data: | |||||||||||||||||||||
| Production: | |||||||||||||||||||||
| Oil – MBbls | 891 | 912 | 3,360 | 3,279 | |||||||||||||||||
| Natural Gas Liquids – MBbls | 1,156 | 782 | 3,914 | 2,796 | |||||||||||||||||
| Natural Gas – MMcf | 14,346 | 14,527 | 56,757 | 48,930 | |||||||||||||||||
| Average Prices: | |||||||||||||||||||||
| Oil price per barrel received |
$ |
94.70 |
$ |
91.67 |
$ |
95.06 |
$ |
92.60 |
|||||||||||||
|
Oil price per barrel received, excluding hedges |
$ |
94.34 |
$ |
85.67 |
$ |
95.18 |
$ |
90.19 |
|||||||||||||
| NGLs price per barrel received | $ | 33.94 | $ | 33.85 | $ | 31.79 | $ | 31.58 | |||||||||||||
|
NGLs price per barrel received, excluding hedges |
$ | 33.94 | $ | 33.39 | $ | 31.79 | $ | 30.70 | |||||||||||||
| Natural gas price per Mcf received | $ | 3.21 | $ | 3.63 | $ | 3.32 | $ | 3.37 | |||||||||||||
|
Natural gas price per Mcf received, excluding hedges |
$ | 3.19 | $ | 3.09 | $ | 3.33 | $ | 2.53 | |||||||||||||
|
Operating profit before depreciation, depletion, amortization, and |
$ |
128.2 |
$ |
120.4 |
$ |
465.7 |
$ |
417.7 |
|||||||||||||
| Contract Drilling Operations Data: | |||||||||||||||||||||
| Rigs utilized | 65.0 | 64.0 | 65.0 | 73.9 | |||||||||||||||||
| Operating margins (2) | 42 | % | 40 | % | 40 | % | 45 | % | |||||||||||||
| Operating profit before depreciation (2) ($MM) | $ | 42.9 | $ | 43.0 | $ | 167.5 | $ | 240.2 | |||||||||||||
| Mid-Stream Operations Data: | |||||||||||||||||||||
| Gas gathering – Mcf/day | 312,254 | 279,990 | 309,554 | 250,290 | |||||||||||||||||
| Gas processing – Mcf/day | 149,069 | 131,570 | 140,584 | 133,987 | |||||||||||||||||
| Liquids sold – Gallons/day | 656,415 | 441,973 | 543,602 | 542,578 | |||||||||||||||||
|
Operating profit before depreciation and amortization (2) ($MM) |
$ | 12.2 | $ | 6.4 | $ | 43.9 | $ | 30.2 | |||||||||||||
|
(1) The company considers its cash flow from operations before |
|||||||||||||||||||||
|
(2) Operating profit before depreciation is calculated by taking |
|||||||||||||||||||||
Non-GAAP Financial Measures
Unit Corporation reports its financial results in accordance with
generally accepted accounting principles (“GAAP”). The Company believes
certain non-GAAP performance measures provide users of its financial
information and its management additional meaningful information to
evaluate the performance of the company.
This press release includes cash flow from operations before changes in
operating assets and liabilities, its drilling segment’s average daily
operating margin before elimination of intercompany drilling rig profit,
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, and its unaudited oil and natural gas reserves
reconciliation of PV-10 to standard measure.
Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three and twelve months ended December 31,
2013 and 2012. Non-GAAP financial measures should not be considered by
themselves or a substitute for results reported in accordance with GAAP.
| Unit Corporation | ||||||||||
|
Reconciliation of Cash Flow From Operations Before Changes in |
||||||||||
|
Twelve Months Ended |
||||||||||
| 2013 | 2012 | |||||||||
| (In thousands) | ||||||||||
| Net cash provided by operating activities | $ | 674,331 | $ | 690,911 | ||||||
| Net change in operating assets and liabilities | (36,395 | ) | (26,146 | ) | ||||||
|
Cash flow from operations before changes in operating assets and |
$ | 637,936 | $ | 664,765 | ||||||
________________
The Company has included the cash flow from operations before changes in
operating assets and liabilities because:
-
It is an accepted financial indicator used by its management and
companies in the industry to measure the company’s ability to generate
cash which is used to internally fund its business activities. -
It is used by investors and financial analysts to evaluate the
performance of the company.
| Unit Corporation | |||||||||||||||||||||
| Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit |
|||||||||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||||||||
| September 30, | December 31, | December 31, | |||||||||||||||||||
| 2013 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
| (In thousands except operating days and operating margins) | |||||||||||||||||||||
| Contract drilling revenue | $ | 100,647 | $ | 101,598 | $ | 108,521 | $ | 414,778 | $ | 529,719 | |||||||||||
| Contract drilling operating cost | 58,988 | 58,700 | 65,544 | 247,280 | 289,524 | ||||||||||||||||
| Operating profit from contract drilling | 41,659 | 42,898 | 42,977 | 167,498 | 240,195 | ||||||||||||||||
|
Add: Elimination of intercompany rig profit |
4,579 |
|
5,741 |
|
2,647 |
17,416 |
|
15,583 |
|||||||||||||
|
Operating profit from contract drilling before elimination of |
46,238 |
48,639 |
45,624 |
184,914 | 255,778 | ||||||||||||||||
| Contract drilling operating days | 5,838 | 5,981 | 5,821 | 23,720 | 26,704 | ||||||||||||||||
|
Average daily operating margin before elimination of intercompany |
$ | 7,920 | $ | 8,132 | $ | 7,838 | $ | 7,796 | $ | 9,578 | |||||||||||
________________
The Company has included the average daily operating margin before
elimination of intercompany rig profit because:
-
Its management uses the measurement to evaluate the cash flow
performance of its 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 the company.
| Unit Corporation | |||||||||||||||
| Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share |
|||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||
| December 31, | December 31, | ||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||
|
|
(In thousands except per share amounts) |
||||||||||||||
| Adjusted net income: | |||||||||||||||
| Net income (loss) | $ | 51,301 | $ | (56,547 | ) | $ | 184,746 | $ | 23,176 | ||||||
| Impairment of oil and natural gas properties | — | 104,450 | — | 176,582 | |||||||||||
|
(Gain) loss on derivatives not designated as hedges and hedge |
3,095 | (2,053 | ) | 5,142 | 767 | ||||||||||
|
Settlements during the period of matured derivative contracts (net |
(116 | ) | — | (1,081 | ) | — | |||||||||
| Adjusted net income | $ | 54,280 | $ | 45,850 | $ | 188,807 | $ | 200,525 | |||||||
| Adjusted diluted earnings per share: | |||||||||||||||
| Diluted earnings (loss) per share | $ | 1.05 | $ | (1.18 | ) | $ | 3.80 | $ | 0.48 | ||||||
| Impairment of oil and natural gas properties | — | 2.17 | — | 3.67 | |||||||||||
|
Diluted earnings per share from the (gain) loss on derivatives |
0.06 | (0.04 | ) | 0.11 | 0.01 | ||||||||||
|
Diluted earnings per share from the settlements of matured |
— | — | (0.02 | ) | — | ||||||||||
|
Adjusted diluted earnings per share |
$ | 1.11 | $ | 0.95 | $ | 3.89 | $ | 4.16 | |||||||
________________
The Company has 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:
-
It uses 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.
Unaudited Reconciliation of PV-10 to Standard Measure
December
31, 2013
PV-10 is the estimated future net cash flows from proved reserves
discounted at an annual rate of 10 percent before giving effect to
income taxes. Standardized Measure is the after-tax estimated future
cash flows from proved reserves discounted at an annual rate of 10
percent, determined in accordance with GAAP. The company uses PV-10 as
one measure of the value of its proved reserves and to compare relative
values of proved reserves among exploration and production companies
without regard to income taxes. The company believes that securities
analysts and rating agencies use PV-10 in similar ways. The company’s
management believes PV-10 is a useful measure for comparison of proved
reserve values among companies because, unlike Standardized Measure, it
excludes future income taxes that often depend principally on the
characteristics of the owner of the reserves rather than on the nature,
location and quality of the reserves themselves. Below is a
reconciliation of PV-10 to Standardized Measure:
| 2013 | ||||||
| ($ in billions) | ||||||
| PV-10 at December 31, 2013 | $ | 1.8 | ||||
| Discounted effect of income taxes | (0.6 | ) | ||||
| Standardized Measure at December 31, 2013 | $ | 1.2 | ||||
Unit Corporation
Michael D. Earl, 918-493-7700
Vice President,
Investor Relations
www.unitcorp.com
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