Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the fourth quarter and year end 2014. For the
year, Unit achieved a number of significant milestones:
- Record consolidated revenues of $1.6 billion
-
Record proved reserves of 1.1 Tcfe (179.0 MMBoe), a 12% increase over
2013 - Record annual production of 18.3 MMBoe, a 9% increase over 2013
- Record annual average dayrate of $20,043
-
Successfully initiated the BOSS drilling program by placing three BOSS
rigs into service and obtaining long-term contracts for an additional
five -
Record natural gas gathered, processed and natural gas liquids sold
volumes per day with each increasing 3%, 15% and 35%, respectively,
over 2013
FOURTH QUARTER AND YEAR END 2014 RESULTS
Despite its operational achievements for the year, Unit recorded a net
loss for the quarter of $42.6 million, or $0.88 per diluted share,
compared to net income of $51.3 million, or $1.05 per diluted share, for
the fourth quarter of 2013. Because of the significantly lower commodity
prices existing at year-end 2014, fourth quarter 2014 results included
the following pre-tax non-cash write downs: $76.7 million ceiling test
write down in the carrying value of Unit’s oil and natural gas
properties; $74.3 million for the removal of 31 drillings rigs from the
fleet along with some other equipment; and $7.1 million in the carrying
value of three gas gathering systems. Adjusted net income for the
quarter (which excludes the effect of non-cash commodity derivatives and
the effects of the write-downs) was $39.7 million, or $0.80 per diluted
share (see Non-GAAP Financial Measures below). Total revenues for the
quarter were $378.6 million (43% oil and natural gas, 36% contract
drilling, and 21% mid-stream), compared to $359.1 million (49% oil and
natural gas, 28% contract drilling, and 23% mid-stream) for the fourth
quarter of 2013.
For 2014, net income was $136.3 million, or $2.78 per diluted share,
compared to 2013 net income of $184.7 million, or $3.80 per diluted
share. Excluding the effect of the fourth quarter 2014 write downs
discussed above and the effect of non-cash commodity derivatives,
adjusted net income for 2014 was $212.6 million, or $4.33 per diluted
share (see Non-GAAP Financial Measures below). Total revenues for 2014
were $1,572.9 million (47% oil and natural gas, 30% contract drilling,
and 23% mid-stream), compared to $1,351.9 million (48% oil and natural
gas, 31% contract drilling, and 21% mid-stream) for 2013.
OIL AND NATURAL GAS SEGMENT INFORMATION
Total equivalent production for the quarter was 4.9 million barrels of
oil equivalent (MMBoe), an increase of 10% and 6% over the fourth
quarter of 2013 and the third quarter of 2014, respectively. Liquids
(oil and NGLs) production represented 47% of total equivalent production
for the quarter. Oil production for the quarter was 11,340 barrels per
day, an increase of 17% over the fourth quarter of 2013 and essentially
unchanged from the third quarter of 2014. NGLs production for the
quarter was 13,616 barrels per day, an increase of 8% over the fourth
quarter of 2013 and an increase of 9% over the third quarter of 2014.
Natural gas production for the quarter was 167,721 thousand cubic feet
(Mcf) per day, an increase of 8% over the fourth quarter of 2013 and a
6% increase over the third quarter of 2014. Total production for 2014
was 18.3 MMBoe.
Unit’s average realized per barrel equivalent price for the fourth
quarter was $35.73, a decrease of 7% from the fourth quarter of 2013 and
a decrease of 10% from the third quarter of 2014. Unit’s average natural
gas price for the fourth quarter of 2014 was $3.72 per Mcf, an increase
of 16% over the fourth quarter of 2013 and a 1% increase over the third
quarter of 2014. Unit’s average oil price for the quarter was $81.34 per
barrel, a decrease of 14% from the fourth quarter of 2013 and a decrease
of 11% from the third quarter of 2014. Unit’s average NGLs price for the
quarter was $25.28 per barrel, a 26% decrease from the fourth quarter of
2013 and a decrease of 16% from the third quarter of 2014. For 2014,
Unit’s average natural gas price increased 18% to $3.92 per Mcf as
compared to $3.32 per Mcf for 2013. Unit’s average oil price for 2014
was $89.43 per barrel compared to $95.06 per barrel during 2013, a 6%
decrease. Unit’s average NGLs price for 2014 was $30.95 per barrel
compared to $31.79 per barrel during 2013, a 3% decrease. All prices in
this paragraph include the effects of derivative contracts.
The following table summarizes this segment’s 2015 derivative contracts.
| Crude | |||||||||||||||||||||
| Weighted Average Price | |||||||||||||||||||||
| Period | Type | Volume/Day | Fixed | Floor | Ceiling | ||||||||||||||||
| Jan 15 – Dec 15 | Swaps | 1,000 Bbls | $95.00 | ||||||||||||||||||
| Natural Gas | |||||||||||||||||||||
| Weighted Average Price | |||||||||||||||||||||
| Period | Type | Volume/Day | Fixed | Floor | Ceiling | ||||||||||||||||
| Jan 15 – Dec 15 | Swaps | 40,000 MMBtu | $3.98 | ||||||||||||||||||
| Jan 15 – Mar 15 | Collars | 30,000 MMBtu | $4.20 | $5.03 | |||||||||||||||||
| Apr 15 – Jun 15 | Swaps | 30,000 MMBtu | $3.10 | ||||||||||||||||||
| Apr 15 – Jun 15 | Collars | 30,000 MMBtu | $2.92 | $3.26 | |||||||||||||||||
| Jul 15 – Sep 15 | Collars | 30,000 MMBtu | $2.58 | $3.04 | |||||||||||||||||
The following table illustrates this segment’s comparative production,
realized prices, and operating profit for the periods indicated:
| Three Months Ended | Three Months Ended | Twelve Months Ended | |||||||||||||||||||||||||||||||||||||
| Dec. 31, 2014 | Dec. 31, 2013 | Change | Dec. 31, 2014 | Sept. 30, 2014 | Change | Dec. 31, 2014 | Dec. 31, 2013 | Change | |||||||||||||||||||||||||||||||
| Oil and NGLs Production, MBbl | 2,296 | 2,047 | 12 | % | 2,296 | 2,188 | 5 | % | 8,472 | 7,274 | 16 | % | |||||||||||||||||||||||||||
| Natural Gas Production, Bcf | 15.4 | 14.3 | 8 | % | 15.4 | 14.5 | 6 | % | 58.9 | 56.8 | 4 | % | |||||||||||||||||||||||||||
| Production, MBoe | 4,868 | 4,438 | 10 | % | 4,868 | 4,612 | 6 | % | 18,281 | 16,734 | 9 | % | |||||||||||||||||||||||||||
| Production, MBoe/day | 52.9 | 48.2 | 10 | % | 52.9 | 50.1 | 6 | % | 50.1 | 45.8 | 9 | % | |||||||||||||||||||||||||||
| Avg. Realized Natural Gas Price, Mcfe (1) | $ | 3.72 | $ | 3.21 | 16 | % | $ | 3.72 | $ | 3.68 | 1 | % | $ | 3.92 | $ | 3.32 | 18 | % | |||||||||||||||||||||
| Avg. Realized NGL Price, Bbl(1) | $ | 25.28 | $ | 33.94 | (26 | )% | $ | 25.28 | $ | 30.11 | (16 | )% | $ | 30.95 | $ | 31.79 | (3 | )% | |||||||||||||||||||||
| Avg. Realized Oil Price, Bbl (1) | $ | 81.34 | $ | 94.70 | (14 | )% | $ | 81.34 | $ | 91.57 | (11 | )% | $ | 89.43 | $ | 95.06 | (6 | )% | |||||||||||||||||||||
| Realized Price / Boe (1) | $ | 35.73 | $ | 38.24 | (7 | )% | $ | 35.73 | $ | 39.76 | (10 | )% | $ | 39.25 | $ | 37.77 | 4 | % | |||||||||||||||||||||
|
Operating Profit Before Depreciation, Depletion, Amortization, &
Impairment (MM) (2) |
$ | 111.0 | $ | 128.2 | (13 | )% | $ | 111.0 | $ | 139.6 | (21 | )% | $ | 552.2 | $ | 465.7 | 19 | % | |||||||||||||||||||||
|
(1) Realized price includes oil, natural gas liquids, natural gas and associated derivatives. |
|||||||||||||||||||||||||||||||||||||||
|
(2) Operating profit before depreciation is calculated by taking |
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At the end of 2014, ten Unit drilling rigs were operating for its
exploration segment. Three were operating in the Southern Oklahoma
Hoxbar Oil Trend (SOHOT), three in the Granite Wash (GW), two in the
Wilcox, one in the Marmaton and one in the Mississippian. By the end of
the first quarter and continuing through the second quarter of 2015, the
plan is to have four Unit drilling rigs operating for its exploration
segment. Two of the drilling rigs will be in the SOHOT and two in the
Wilcox. Any adjustments to this level of activity will be dependent on
commodity pricing and/or well results.
In the SOHOT area, production increased 45% during the quarter as
compared to the third quarter of 2014. During the quarter, four new
horizontal operated Hoxbar wells were completed. Three wells were
completed in the Medrano member of the Hoxbar and one well in the
Marchand member. The 30 day initial production rate for the three
Medrano wells, fracture stimulated with larger fracs, averaged 13.8
MMcfe per day, which is approximately 78% higher compared to Unit’s
prior Medrano completions. The average production mix of the three wells
is 4% oil, 26% NGLs, and 70% natural gas. The completed Marchand well
during the fourth quarter had a 30 day initial production rate of
approximately 1,205 Boe per day, consisting of 82% oil, 9% NGLs, and 9%
natural gas. The current plan for 2015 is to average one to two Unit
rigs drilling in the prospect, which should equate to approximately 14
new horizontal Hoxbar completions, of which approximately 75% of the
wells are anticipated to be in the Medrano. The estimated 2015 capital
spending for drilling in the SOHOT is approximately $90 million.
In the Wilcox area, production increased 13% during the quarter as
compared to the third quarter 2014 and increased 28% during 2014
compared to 2013. During the quarter, the BS O#2 (100% working
interest), located on the east side of the Gilly field, was completed
from approximately 91 net feet of Lower Wilcox sand flowing
approximately 135 barrels of oil per day, 464 barrels of NGLs per day,
and 6,500 Mcf per day (gross volumes) with 6,100 psi flowing tubing
pressure. The well penetrated approximately 453 feet of additionalpotential
pay sands and potentially extends the eastern extent of the Gilly field.
At the end of 2014, the Gilly field is estimated to contain
approximately 418 Bcfe gross and 302 Bcfe net of volumetric resource
potential. To date, approximately 10% has been produced, and
approximately 43% is booked as remaining proved reserves. The estimated
2015 capital spending for drilling in the Wilcox area is approximately
$100 million. The current plan is to utilize one to two Unit drilling
rigs in 2015, which should result in approximately eight vertical and
six horizontal Wilcox completions.
YEAR END 2014 ESTIMATED PROVED RESERVES
The PV-10 value of Unit’s estimated year-end 2014 proved reserves
increased 17% over 2013 to $2.1 billion. Unit’s estimated year-end 2014
proved oil and natural gas reserves were 179.0 MMBoe, or 1.1 trillion
cubic feet of natural gas equivalents (Tcfe), as compared with 159.9
MMBoe, or 960 billion cubic feet of natural gas equivalents (Bcfe), at
year-end 2013, a 12% increase in its estimated proved reserves. From all
sources, Unit replaced approximately 204% of its 2014 production.
Estimated reserves were 13% oil, 27% NGLs, and 60% natural gas. During
2014, Unit divested 1.4 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 2014:
|
Oil |
NGLs |
Natural Gas |
Proved Reserves (MMBoe) |
|||||||||||||
| Proved Reserves, at December 31, 2013 | 21.8 | 41.2 | 581.8 | 159.9 | ||||||||||||
| Revisions of previous estimates | (3.2 | ) | (2.3 | ) | (32.8 | ) | (10.9 | ) | ||||||||
|
Extensions, discoveries, and other additions |
8.1 |
14.4 |
160.7 |
49.3 |
||||||||||||
| Purchases of minerals in place | 0.2 | 0.1 | 0.4 | 0.4 | ||||||||||||
| Production | (3.8 | ) | (4.6 | ) | (58.8 | ) | (18.3 | ) | ||||||||
| Sales | (0.4 | ) | (0.3 | ) | (4.3 | ) | (1.4 | ) | ||||||||
| Proved Reserves, at December 31, 2014 | 22.7 | 48.5 | 647.0 | 179.0 | ||||||||||||
Estimated 2014 year-end proved reserves included proved developed
reserves of 137 MMBoe, or 821 Bcfe, (13% oil, 26% NGLs, and 61% natural
gas) and proved undeveloped reserves of 42 MMBoe, or 253 Bcfe, (12% oil,
30% NGLs, and 58% natural gas). Overall, 76% of Unit’s estimated proved
reserves are proved developed.
The present value of the estimated future net cash flows from the 2014
estimated proved reserves (before income taxes and using a 10% discount
rate (PV-10)), is approximately $2.1 billion. The present value was
determined using the 12 month 2014 average prices received. The
aggregate price used for all future reserves was $94.99 per barrel of
oil, $45.25 per barrel of NGLs, and $4.36 per Mcf of natural gas. Unit’s
2014 year-end proved reserves were independently audited by Ryder Scott
Company, L.P. Their audit covered properties which accounted for 85% 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.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “For
our oil and natural gas segment, fourth quarter production increased 10%
over the comparable quarter of 2013 and increased 6% over the third
quarter of 2014. Once again, we achieved our goal of replacing at least
150% of each year’s production with new reserves, achieving 204%
production replacement in 2014. Our 2015 production guidance is
approximately 18.6 to 19.0 MMBoe, an increase of 2% to 4% over 2014,
although actual results will continue to be subject to industry
conditions. Unit has a strong asset base, and we have a proven record of
weathering the storms of these unfavorable pricing cycles.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the quarter was 80.9, an
increase of 24% over the fourth quarter of 2013, and an increase of 2%
over the third quarter of 2014. Per day drilling rig rates for the
quarter averaged $20,488, an increase of 4% over the fourth quarter of
2013 and 2% over the third quarter of 2014. Average per day operating
margin for the quarter was $8,834 (before elimination of intercompany
drilling rig profit and bad debt expense of $8.7 million). This compares
to $8,132 (before elimination of intercompany drilling rig profit and
bad debt expense of $5.7 million) for the fourth quarter of 2013, an
increase of 9%, or $702. As compared to the third quarter of 2014
($8,449 before elimination of intercompany drilling rig profit and bad
debt expense of $7.6 million), fourth quarter 2014 operating margin
increased 5% or $385 (in each case regarding eliminating intercompany
drilling rig profit and bad debt expense – see Non-GAAP Financial
Measures below). Average operating margins for the fourth quarter of
2014 included early termination fees of approximately $27 per day from
the cancellation of certain long-term contracts, compared to $161 per
day for the fourth quarter of 2013.
For 2014, Unit averaged 75.4 drilling rigs working, an increase of 16%
over 65.0 drilling rigs working during 2013. Average per day operating
margin for 2014 was $8,392 (before elimination of intercompany drilling
rig profit and bad debt expense of $29.3 million) as compared to $7,796
(before elimination of intercompany drilling rig profit of $17.4
million) for 2013, an increase of 8% (in each case regarding eliminating
intercompany drilling rig profit see Non-GAAP Financial Measures below).
For 2014, average operating margins included early termination fees of
approximately $7 per day from the cancellation of certain long-term
contracts, compared to $80 per day for 2013.
Larry Pinkston said: “Drilling rig demand declined during the latter
part of the quarter because of the significant decrease in commodity
prices. During the quarter, our third BOSS drilling rig began operating.
At year end, we removed 31 drilling rigs from our fleet as well as some
other equipment. With the addition of our fourth BOSS drilling rig that
began operating in January 2015 and the reduction of the 31 drilling
rigs at year end, our current drilling rig fleet now totals 90 drilling
rigs, of which 47 are working under contract. Long-term contracts
(contracts with original terms ranging from six months to two years in
length) are in place for 21 of the 47 drilling rigs. To date, we have
received early termination notices for eight of these contracts. Of the
21 long term contracts, four are up for renewal in the first quarter of
2015, five in the second quarter, four in the third quarter, two in the
fourth quarter, and six are up for renewal in 2016. Currently we have
four BOSS drilling rigs operating, and four additional BOSS drilling
rigs have been contracted to be built for third party operators and are
expected to be placed into service during 2015. We will delay
fabrication of any additional BOSS drilling rigs until contracts are
received.”
|
The following table illustrates certain comparative results from |
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| Three Months Ended | Three Months Ended | Twelve Months Ended | |||||||||||||||||||||||||
| Dec. 31, 2014 | Dec. 31, 2013 | Change | Dec. 31, 2014 | Sept. 30, 2014 | Change | Dec. 31, 2014 | Dec. 31, 2013 | Change | |||||||||||||||||||
| Rigs Utilized | 80.9 | 65.0 | 24% | 80.9 | 79.1 | 2% | 75.4 | 65.0 | 16% | ||||||||||||||||||
| Operating Profit Before Depreciation & Impairment (MM) (1) | $ 57.1 | $ 42.9 | 33% | $ 57.1 | $ 53.9 | 6% | $ 201.6 | $ 167.5 | 20% | ||||||||||||||||||
|
(1) Operating profit before depreciation is calculated by taking |
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MID-STREAM SEGMENT INFORMATION
For the quarter, per day liquids sold and gas gathered volumes both
increased 5% while gas processed volumes increased 10% as compared to
the fourth quarter of 2013. Compared to the third quarter of 2014,
liquids sold and processed volumes per day decreased 11% and 3%,
respectively, while gathered volumes per day increased 2%. Operating
profit (as defined in the footnote below) for the quarter was $10.0
million, a decrease of 18% from the fourth quarter of 2013 and a
decrease of 25% from the third quarter of 2014.
|
The following table illustrates certain comparative results from |
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| Three Months Ended | Three Months Ended | Twelve Months Ended | ||||||||||||||||||||||||||||||||||
| Dec. 31, 2014 | Dec. 31, 2013 | Change | Dec. 31, 2014 | Sept. 30, 2014 | Change | Dec. 31, 2014 | Dec. 31, 2013 | Change | ||||||||||||||||||||||||||||
| Gas Gathering, Mcf/day | 327,331 | 312,254 | 5 | % | 327,331 | 319,692 | 2 | % | 319,348 | 309,554 | 3 | % | ||||||||||||||||||||||||
| Gas Processing, Mcf/day | 163,979 | 149,069 | 10 | % | 163,979 | 169,357 | (3 | )% | 161,282 | 140,584 | 15 | % | ||||||||||||||||||||||||
| Liquids Sold, Gallons/day | 687,713 | 656,415 | 5 | % | 687,713 | 771,334 | (11 | )% | 733,406 | 543,602 | 35 | % | ||||||||||||||||||||||||
|
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (1) |
$ | 10.0 | $ | 12.2 | (18 | )% | $ | 10.0 | $ | 13.3 | (25 | )% | $ | 49.5 | $ | 43.9 | 13 | % | ||||||||||||||||||
|
(1) Operating profit before depreciation is calculated by taking |
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Larry Pinkston said: “During 2014, we completed construction of a
nine-mile pipeline that connects the Buffalo Wallow gathering system to
our Hemphill processing system. Beginning January 1, 2015, this pipeline
became fully operational, and we began processing Buffalo Wallow
production at our Hemphill facility. We have several new wells to be
connected to our Hemphill system in the next few months, and we are
continuing to connect wells to the Buffalo Wallow system as they are
completed. Our Snowshoe project in Centre County, Pennsylvania is in
process. The project consists of a seven-mile, 16 inch and 24 inch
trunkline to gather Marcellus production for delivery to an interstate
pipeline. Construction of this project is expected to be completed in
the third quarter of 2015.”
2015 CAPITAL EXPENDITURE BUDGET
Unit reduced its operating segment capital expenditures budget for 2015
by 52% compared to 2014, excluding acquisitions and asset retirement
obligation liability, in order to focus on keeping its capital
expenditures substantially within anticipated internally generated cash
flow. The capital expenditures budget is allocated among Unit’s three
business segments as follows: $308.5 million for its oil and natural gas
segment; $99.7 million for its contract drilling segment; and $68.4
million for its midstream segment. This budget does not include costs
for any possible acquisitions, and is based on realized prices for the
year averaging $53.73 per barrel of oil, $17.03 per barrel of natural
gas liquids, and $3.18 per Mcf of natural gas.
This budget is subject to possible periodic adjustments for various
reasons including changes in commodity prices and industry conditions.
Funding for the budget will come primarily from internally generated
cash flow, proceeds from additional non-core asset divestitures, and (if
necessary) borrowings under Unit’s bank credit facility.
FINANCIAL INFORMATION
Unit ended the fourth quarter with long-term debt of $812.2 million
(consisting of $646.2 million of senior subordinated notes net of
unamortized discount and $166.0 million of borrowings under its credit
agreement). Unit’s credit agreement provides that the amount Unit can
borrow is the lesser of the amount it elects as the commitment amount
(currently $500 million) or the value of its borrowing base as
determined by the lenders (currently $900 million), but in either event
not to exceed $900 million.
WEBCAST
Unit will webcast its fourth quarter and year-end earnings conference
call live over the Internet on February 24, 2015 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 Highlights (In thousands except per share amounts) |
|||||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||||
| December 31, | December 31, | ||||||||||||||||
| 2014 | 2013 | 2014 | 2013 | ||||||||||||||
| Statement of Operations: | |||||||||||||||||
| Revenues: | |||||||||||||||||
| Oil and natural gas | $ | 164,903 | $ | 173,990 | $ | 740,079 | $ | 649,718 | |||||||||
| Contract drilling | 134,987 | 101,598 | 476,517 | 414,778 | |||||||||||||
| Gas gathering and processing | 78,661 | 83,533 | 356,348 | 287,354 | |||||||||||||
| Total revenues | 378,551 | 359,121 | 1,572,944 | 1,351,850 | |||||||||||||
| Expenses: | |||||||||||||||||
| Oil and natural gas: | |||||||||||||||||
| Operating costs | 53,937 | 45,830 | 187,916 | 184,001 | |||||||||||||
|
Depreciation, depletion, and amortization |
75,130 | 62,886 | 276,088 | 226,498 | |||||||||||||
| Impairment of oil & gas properties | 76,683 | — | 76,683 | — | |||||||||||||
| Contract drilling: | |||||||||||||||||
| Operating costs | 77,908 | 58,700 | 274,933 | 247,280 | |||||||||||||
| Depreciation and impairment | 98,494 | 18,624 | 159,688 | 71,194 | |||||||||||||
| Gas gathering and processing: | |||||||||||||||||
| Operating costs | 68,665 | 71,341 | 306,831 | 243,406 | |||||||||||||
|
Depreciation, amortization and impairment |
17,530 | 9,048 | 47,502 | 33,191 | |||||||||||||
| General and administrative | 11,614 | 10,035 | 42,023 | 38,323 | |||||||||||||
| (Gain) loss on disposition of assets | 139 | (9,332 | ) | (8,953 | ) | (17,076 | ) | ||||||||||
| Total operating expenses | 480,100 | 267,132 | 1,362,711 | 1,026,817 | |||||||||||||
| Income (loss) from operations | (101,549 | ) | 91,989 | 210,233 | 325,033 | ||||||||||||
| Other income (expense): | |||||||||||||||||
| Interest, net | (5,170 | ) | (3,238 | ) | (17,371 | ) | (15,015 | ) | |||||||||
|
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net |
39,381 |
(5,034 |
) |
30,147 |
(8,374 |
) |
|||||||||||
| Other | (73 | ) | (4 | ) | (70 | ) | (175 | ) | |||||||||
| Total other income (expense) | 34,138 | (8,276 | ) | 12,706 | (23,564 | ) | |||||||||||
| Income (loss) before income taxes | (67,411 | ) | 83,713 | 222,939 | 301,469 | ||||||||||||
| Income tax expense (benefit): | |||||||||||||||||
| Current | (14,343 | ) | 9,246 | 9,378 | 15,991 | ||||||||||||
| Deferred | (10,517 | ) | 23,166 | 77,285 | 100,732 | ||||||||||||
| Total income taxes | (24,860 | ) | 32,412 | 86,663 | 116,723 | ||||||||||||
| Net income (loss) | $ | (42,551 | ) | $ | 51,301 | $ | 136,276 | $ | 184,746 | ||||||||
| Net income (loss) per common share: | |||||||||||||||||
| Basic | $ | (0.88 | ) | $ | 1.06 | $ | 2.80 | $ | 3.83 | ||||||||
| Diluted | $ | (0.88 | ) | $ | 1.05 | $ | 2.78 | $ | 3.80 | ||||||||
| Weighted average shares outstanding: | |||||||||||||||||
| Basic | 48,656 | 48,292 | 48,611 | 48,218 | |||||||||||||
| Diluted | 48,656 | 48,795 | 49,083 | 48,572 | |||||||||||||
| December 31, | December 31, | ||||||||
| 2014 | 2013 | ||||||||
| Balance Sheet Data: | |||||||||
| Current assets | $ | 252,491 | $ | 212,031 | |||||
| Total assets | $ | 4,473,728 | $ | 4,022,390 | |||||
| Current liabilities | $ | 304,171 | $ | 243,573 | |||||
| Long-term debt | $ | 812,163 | $ | 645,696 | |||||
| Other long-term liabilities | $ | 148,785 | $ | 158,331 | |||||
| Deferred income taxes | $ | 876,215 | $ | 801,398 | |||||
| Shareholders’ equity | $ | 2,332,394 | $ | 2,173,392 | |||||
| Twelve Months Ended December 31, | |||||||
| 2014 | 2013 | ||||||
| Statement of Cash Flows Data: | |||||||
|
Cash flow from operations before changes in operating assets and |
$ | 764,984 | $ | 637,936 | |||
| Net change in operating assets and liabilities | (55,991) | 36,395 | |||||
| Net cash provided by operating activities | $ | 708,993 | $ | 674,331 | |||
| Net cash used in investing activities | $ | (920,597) | $ | (579,180) | |||
| Net cash provided by (used in) financing activities | $ | 194,060 | $ | (77,532) | |||
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 net income and earnings per share including
impairment adjustments and the effect of the cash settled commodity
derivatives, unaudited oil and natural gas reserves reconciliation of
PV-10 to standard measure, its drilling segment’s average daily
operating margin before elimination of intercompany drilling rig profit
and bad debt expense, and its cash flow from operations before changes
in operating assets and liabilities.
Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three and twelve months ended December 31,
2014 and 2013. Non-GAAP financial measures should not be considered by
themselves or a substitute for results reported in accordance with GAAP.
|
Unit Corporation Reconciliation of Adjusted Net Income and Adjusted Diluted |
||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
|
|
(In thousands except earnings per share) |
|||||||||||||||
| Adjusted net income: | ||||||||||||||||
| Net income (loss) | $ | (42,551 | ) | $ | 51,301 | $ | 136,276 | $ | 184,746 | |||||||
| Impairment adjustment (net of income tax) | 98,398 | — | 98,398 | — | ||||||||||||
|
(Gain) loss on derivatives not designated as hedges and hedge |
(24,088 | ) | 3,095 | (18,429 | ) | 5,142 | ||||||||||
|
Settlements during the period of matured derivative contracts (net |
7,944 | (116 | ) | (3,691 | ) | (1,081 | ) | |||||||||
| Adjusted net income | $ | 39,703 | $ | 54,280 | $ | 212,554 | $ | 188,807 | ||||||||
| Adjusted diluted earnings per share: | ||||||||||||||||
| Diluted earnings (loss) per share | $ | (0.88 | ) | $ | 1.05 | $ | 2.78 | $ | 3.80 | |||||||
| Diluted earnings per share from the impairments | 2.02 | — | 2.01 | — | ||||||||||||
|
Diluted earnings per share from the (gain) loss on derivatives |
(0.51 | ) | 0.06 | (0.38 | ) | 0.11 |
|
|||||||||
|
Diluted earnings (loss) per share from the settlements of matured |
0.17 | — | (0.08 | ) | (0.02 | ) | ||||||||||
| Adjusted diluted earnings per share | $ | 0.80 | $ | 1.11 | $ | 4.33 | $ | 3.89 | ||||||||
________________
The Company has included the net income and diluted earnings per share
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 analysts.
Unaudited Reconciliation of PV-10 to Standard Measure
December
31, 2014
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:
| 2014 | |||||
| (In billions) | |||||
| PV-10 at December 31, 2014 | $ | 2.1 | |||
| Discounted effect of income taxes | (0.7 | ) | |||
| Standardized Measure at December 31, 2014 | $ | 1.4 | |||
|
Unit Corporation Reconciliation of Average Daily Operating Margin Before |
||||||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||||||
| September 30, | December 31, | December 31, | ||||||||||||||||||
| 2014 | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
| (In thousands except operating days and operating margins) | ||||||||||||||||||||
| Contract drilling revenue | $ | 120,652 | $ | 134,987 | $ | 101,598 | $ | 476,517 | $ | 414,778 | ||||||||||
| Contract drilling operating cost | 66,727 | 77,908 | 58,700 | 274,933 | 247,280 | |||||||||||||||
| Operating profit from contract drilling | 53,925 | 57,079 | 42,898 | 201,584 | 167,498 | |||||||||||||||
|
Add: |
7,553 |
|
8,669 |
|
5,741 |
29,343 |
|
17,416 |
||||||||||||
|
Operating profit from contract drilling before elimination of |
61,478 | 65,748 | 48,639 | 230,927 | 184,914 | |||||||||||||||
| Contract drilling operating days | 7,276 | 7,443 | 5,981 | 27,516 | 23,720 | |||||||||||||||
|
Average daily operating margin before elimination of intercompany |
$ | 8,449 | $ | 8,834 | $ | 8,132 | $ | 8,392 | $ | 7,796 | ||||||||||
________________
The Company has included the average daily operating margin before
elimination of intercompany rig profit and bad debt expense 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 Cash Flow From Operations Before Changes in |
||||||||
| Twelve Months Ended
December 31, |
||||||||
| 2014 | 2013 | |||||||
| (In thousands) | ||||||||
| Net cash provided by operating activities | $ | 708,993 | $ | 674,331 | ||||
| Net change in operating assets and liabilities | 55,991 | (36,395 | ) | |||||
|
Cash flow from operations before changes in operating assets and |
$ | 764,984 | $ | 637,936 | ||||
________________
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
Michael D. Earl, 918-493-7700
Vice President,
Investor Relations
www.unitcorp.com
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