Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the second quarter of 2015. Highlights for
the quarter include:
- Total production of 5.1 million barrels
of oil equivalent (MMBoe), a 9% increase over the second quarter of
2014
- Oil and natural gas liquids (NGLs)
production increased 8% over the second quarter of 2014
- Placed three BOSS drilling rigs into
service during the quarter
- Gas gathered and gas processed volumes
per day increased 11% and 15%, respectively, over the second
quarter of 2014
SECOND QUARTER AND FIRST SIX MONTHS 2015 RESULTS
Because of significantly lower commodity prices, Unit’s second
quarter of 2015 results include the following pre-tax non-cash
write downs: $410.5 million ceiling test write down in the carrying
value of the company’s oil and natural gas properties and an $8.3
million pre-tax write down for the decline in the carrying value of
certain drilling rigs and other assets removed from service. As a
result, Unit recorded a net loss of $274.4 million, or $5.58 per
share, compared to net income of $54.4 million, or $1.11 per
diluted share, for the second quarter of 2014. Adjusted net loss
for the quarter (which excludes the effect of non-cash commodity
derivatives and the effects of the write-downs) was $5.9 million,
or $0.12 per diluted share (see Non-GAAP Financial Measures below).
Total revenues for the quarter were $214.4 million (50% oil and
natural gas, 26% contract drilling, and 24% mid-stream), compared
to $405.4 million (49% oil and natural gas, 28% contract drilling,
and 23% mid-stream) for the second quarter of 2014.
For the first six months of 2015, Unit recorded an $811.1
million pre-tax non-cash ceiling test write down in the carrying
value of the company’s oil and natural gas properties and an $8.3
million pre-tax write down for the drilling rigs and other assets
discussed above. As a result, Unit recorded a net loss of $522.7
million, or $10.66 per share, compared to net income of $111.3
million, or $2.27 per diluted share, for the first six months of
2014. Adjusted net loss for the first six months (which excludes
the effect of non-cash commodity derivatives and the effects of the
write-downs) was $2.2 million, or $0.05 per diluted share (see
Non-GAAP Financial Measures below). Total revenues for the first
six months were $469.5 million (45% oil and natural gas, 32%
contract drilling, and 23% mid-stream), compared to $793.4 million
(49% oil and natural gas, 28% contract drilling, and 23%
mid-stream) for the first six months of 2014.
OIL AND NATURAL GAS SEGMENT INFORMATION
Total equivalent production for the quarter was 5.1 million
barrels of oil equivalent (MMBoe), an increase of 9% over the
second quarter of 2014 and a 1% decrease from the first quarter of
2015. Liquids (oil and NGLs) production represented 45% of total
equivalent production for the quarter. Oil production for the
quarter was 10,418 barrels per day, essentially unchanged from the
second quarter of 2014 and a decrease of 15% from the first quarter
of 2015. NGLs production for the quarter was 14,599 barrels per
day, an increase of 14% over the second quarter of 2014 and an
increase of 2% over the first quarter of 2015. Natural gas
production for the quarter was 183,135 thousand cubic feet (Mcf)
per day, an increase of 11% over the second quarter of 2014 and an
increase of 1% over the first quarter of 2015. Total production for
the first six months of 2015 was 10.2 MMBoe.
Unit’s average realized per barrel equivalent price for the
second quarter was $22.38, a decrease of 44% from the second
quarter of 2014 and a 2% increase from the first quarter of 2015.
Unit’s average natural gas price for the second quarter of 2015 was
$2.67 per Mcf, a decrease of 34% from the second quarter of 2014
and a 9% decrease from the first quarter of 2015. Unit’s average
oil price for the quarter was $55.52 per barrel, a decrease of 41%
from the second quarter of 2014 and an increase of 15% over the
first quarter of 2015. Unit’s average NGLs price for the quarter
was $12.05 per barrel, a 60% decrease from the second quarter of
2014 and an increase of 39% over the first quarter of 2015. All
prices in this paragraph include the effects of derivative
contracts.
The following table summarizes this segment’s outstanding
derivative contracts.
Crude Swap Volume
Collar Volume Weighted Average
Weighted Average Weighted
Average Period Bbl/Day
Bbl/Day Swap Price
Floor Price Ceiling Price Q3 2015
1,000 2,000 $95.00
$58.00 $64.40 Q4 2015 1,000
2,000 $95.00 $58.00
$64.40
Natural Gas Swap Volume
Collar Volume Weighted Average Weighted
Average Weighted Average Period
MMBtu/Day MMBtu/Day
Swap Price Floor Price
Ceiling Price Q3 2015 40,000
30,000 $3.98 $2.58 $3.04
Q4 2015 40,000 --- $3.98
--- --- 2016 10,000
--- $3.25 ---
---
The following table illustrates this segment’s comparative
production, realized prices, and operating profit for the periods
indicated:
Three Months Ended
Three Months Ended
Six Months Ended June 30, 2015
June 30, 2014 Change
June 30, 2015 Mar. 31, 2015
Change June 30, 2015 June 30,
2014 Change Oil and NGLs Production, MBbl
2,277 2,113
8 % 2,277 2,384 (4 )%
4,661 3,989 17 % Natural
Gas Production, Bcf 16.7
15.0 11 % 16.7 16.4
2 % 33.1 28.9
14 % Production, MBoe 5,054
4,618 9 % 5,054
5,117 (1 )% 10,171
8,802 16 % Production, MBoe/day
55.5 50.7 9 % 55.5
56.9 (2 )% 56.2
48.6 16 % Avg. Realized Natural Gas Price, Mcf
(1) $ 2.67 $ 4.05 (34 )%
$ 2.67 $ 2.94 (9 )% $ 2.80
$ 4.14 (32 )% Avg. Realized NGL Price, Bbl (1)
$ 12.05 $ 29.99 (60 )% $
12.05 $ 8.65 39 % $ 10.37
$ 34.57 (70 )% Avg. Realized Oil Price, Bbl (1)
$ 55.52 $ 94.17 (41 )% $
55.52 $ 48.47 15 % $ 51.73
$ 92.95 (44 )% Realized Price / Boe (1)
$ 22.38 $ 40.10 (44 )% $ 22.38
$ 21.99 2 % $ 22.18 $
40.93 (46 )% Operating Profit Before Depreciation,
Depletion, & Amortization (MM) (2) $ 61.3
$ 153.8 (60 )% $ 61.3
$ 60.9 1 % $ 122.1
$ 301.6 (60 )%
(1) Realized price includes oil, natural gas liquids, natural
gas, and associated derivatives.
(2) Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses
excluding depreciation, depletion, amortization, and
impairment.
Currently, two Unit drilling rigs are operating for this
segment. One is operating in the Southern Oklahoma Hoxbar Oil Trend
(SOHOT) and one is drilling in the Wilcox play, located in
southeast Texas. The current plan is to have two Unit drilling rigs
operating through the end of the third quarter at which time
adjustments may be made depending on factors such as commodity
pricing, service costs and/or well results. Unit’s expectations are
to be at the top end of the production guidance of 2% to 4%. Well
service cost reductions and operating efficiencies are resulting in
current AFE’s being approximately 28% lower as compared to
2014.
In the SOHOT area, production increased 5% during the quarter as
compared to the first quarter of 2015. During the first half of
2015, three horizontal operated Hoxbar wells were completed in the
first quarter and five horizontal Hoxbar wells were completed in
the second quarter for a total of eight wells. Six of the eight new
wells were completed in the Medrano member of the Hoxbar and two
wells in the Marchand member. The 30 day initial production rate
for the six Medrano wells averaged 7 MMcfe per day of which
approximately 32% consisted of liquids. The two Marchand wells had
a 30 day average initial production rate of approximately 1,571 Boe
per day with 84% of the production mix being oil. The current plan
for 2015 is to utilize one to two Unit rigs drilling in the
prospect for the remainder of 2015, which should equate to
approximately 12 to 14 new horizontal Hoxbar completions.
In the Wilcox area, production was essentially unchanged during
the quarter as compared to the first quarter 2015 after accounting
for a reduction of 0.75 Bcfe due to a third party processing plant
being shut in for maintenance. Without the reduction, Wilcox
production would have increased approximately 11% for the quarter.
For the first half 2015, three Wilcox wells were completed in the
first quarter and five Wilcox wells were completed in the second
quarter for a total of eight wells (five vertical and three
horizontal). Because of a lack of sufficient production history and
pending lease acquisition opportunities, we have elected not to
discuss the performance of the horizontal wells at this time. Two
additional horizontal wells are scheduled to be drilled late in the
fourth quarter of 2015. Development of the Gilly Downthrown fault
block is progressing favorably. Four vertical Wilcox wells have
been drilled and logged an average of approximately 200 feet of
potential oil and gas pay from multiple Wilcox sands. Completion
operations have begun on all four wells and current plans are to
drill two to three additional vertical delineation wells this year.
The preliminary field size based on the four wells is estimated at
approximately 1,000 acres. In the Wilcox project, the current plan
is to utilize one to two Unit drilling rigs in 2015, which should
result in approximately 11 vertical and five horizontal Wilcox
completions.
In the Granite Wash, a horizontal “C1” well was completed with
an extended lateral of approximately 6,600 feet. The well, which is
the first extended lateral drilled in this sand, had an average IP
30 rate of 10.7 MMcfe per day consisting of 42% natural gas, 35%
oil, and 23% NGLs production. This was a 39% increase in the IP 30
rate over the typical “C1” well with a lateral length of 4,600
feet.
Larry Pinkston, Unit’s Chief Executive Officer and President,
said: “Due to the unexpected shut in of some of the production in
East Texas because of maintenance of a third party processing
facility, production for the quarter was negatively impacted by
approximately 125,000 Boe. We have reduced our drilling activities
during the quarter because of the continued lower commodity prices.
Despite the slowdown, we are pleased with the quality of the wells
that we are drilling and completing. In the two core areas where we
are allocating capital we have a multi-year inventory of potential
drilling locations that can meet or exceed our profitability
hurdles in this challenging commodity price environment.”
CONTRACT DRILLING SEGMENT INFORMATION
The average number of drilling rigs used in the quarter was
30.7, a decrease of 58% from the second quarter of 2014, and a
decrease of 39% from the first quarter of 2015. Per day drilling
rig rates for the quarter averaged $19,881, essentially unchanged
from the second quarter of 2014 and a 1% decrease from the first
quarter of 2015. Average per day operating margin for the quarter
was $6,821 (before elimination of intercompany drilling rig profit
and bad debt expense of $0.5 million). This compares to $8,317
(before elimination of intercompany drilling rig profit and bad
debt expense of $7.8 million) for the second quarter of 2014, a
decrease of 18%, or $1,496. As compared to $10,253 (before
elimination of intercompany drilling rig profit and bad debt
expense of $2.9 million) for the first quarter of 2015, second
quarter 2015 operating margin decreased 33% or $3,432 (in each case
regarding eliminating intercompany drilling rig profit and bad debt
expense - see Non-GAAP Financial Measures below). Average operating
margins for the second quarter of 2015 included early termination
fees of approximately $1.6 million, or $594 per day, from the
cancellation of certain long-term contracts, compared to no early
termination fees during the second quarter of 2014 and $12.7
million for the first quarter of 2015.
Larry Pinkston said: “Drilling rig demand continued to decline
during the second quarter because of the significant decrease in
commodity prices. During the quarter, our sixth, seventh, and
eighth BOSS drilling rigs began operating. With adding these three
BOSS drilling rigs, our current drilling rig fleet now totals 94
drilling rigs, of which 32 are now working under contract. We have
recently been notified of a customer's intent to terminate early
the contracts on two BOSS drilling rigs both of which are under
term contracts that contain early termination penalties. Long-term
contracts (contracts with original terms ranging from six months to
two years in length) are in place for 14 of the 32 drilling rigs.
Of the 14 long-term contracts, three are up for renewal during the
third quarter, one in the fourth quarter, seven in 2016 and three
in 2017.”
The following table illustrates certain comparative results from
this segment’s operations for the periods indicated:
Three Months Ended
Three Months Ended
Six Months Ended June 30, 2015
June 30, 2014 Change
June 30, 2015 Mar. 31, 2015
Change June 30, 2015 June 30,
2014 Change Rigs Utilized
30.7 73.5 (58 )%
30.7 50.1 (39 )% 40.4
70.7 (43 )% Operating Profit
Before Depreciation, Depletion, & Amortization (MM) (1)
$ 18.5 $ 47.8 (61 )%
$ 18.5 $ 43.3 (57 )%
$ 61.9 $ 90.6 (32
)%
(1) Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses
excluding depreciation and impairment.
MID-STREAM SEGMENT INFORMATION
For the quarter, per day gas gathered and gas processed volumes
increased 11% and 15%, respectively, while liquids sold volumes
decreased 21% as compared to the second quarter of 2014. Compared
to the first quarter of 2015, gas gathered and liquids sold volumes
per day increased 9% and 5%, respectively, while gas processed
volumes per day decreased 2%. Operating profit (as defined in the
footnote below) for the quarter was $11.6 million, a decrease of
17% from the second quarter of 2014 and an increase of 18% over the
first quarter of 2015.
For the first six months, per day gas gathered and gas processed
volumes increased 11% and 20%, respectively, while liquids sold
volumes per day decreased 21% as compared to the first six months
of 2014. Operating profit (as defined in the footnote below) for
the first six months was $21.4 million, a decrease of 18% from the
first six months of 2014.
The following table illustrates certain comparative results from
this segment’s operations for the periods indicated:
Three Months Ended
Three Months Ended
Six Months Ended June 30, 2015
June 30, 2014 Change
June 30, 2015 Mar. 31, 2015
Change June 30, 2015 June 30,
2014 Change Gas Gathering, Mcf/day
362,896 326,028 11
% 362,896 334,278 9 %
348,666 315,116 11 % Gas
Processing, Mcf/day 186,041
161,509 15 % 186,041
189,160 (2 )% 187,592
155,807 20 % Liquids Sold, Gallons/day
599,732 762,205
(21 )% 599,732 568,876 5
% 584,389 737,353 (21 )%
Operating Profit Before Depreciation, Depletion, & Amortization
(MM) (1) $ 11.6 $ 14.0
(17 )% $ 11.6 $ 9.8
18 % $ 21.4 $ 26.2
(18 )%
(1) Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses
excluding depreciation, amortization, and impairment.
Larry Pinkston said: “We continue to operate in full ethane
rejection mode due to the decline in liquids prices that have
adversely impacted our liquids sold volumes. Gathering volumes
continue to increase through the second quarter as our facilities
are positioned well to take advantage of operator activity.
Progress continues to be made on the Snowshoe project in Centre
County, Pennsylvania with the completion expected to be by the end
of 2015.”
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $926.9 million
(consisting of $646.4 million of senior subordinated notes net of
unamortized discount and $280.5 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 $725
million), but in either event not to exceed $900 million. The
credit agreement was amended during the second quarter to provide
for a new maturity date of April 2020 and establish the current
borrowing base amount noted above.
WEBCAST
Unit will webcast its second quarter earnings conference call
live over the Internet on August 4, 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, 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 Six Months Ended June
30, June 30, 2015
2014 2015 2014
Statement of Operations: Revenues: Oil and natural gas $
107,256 $ 198,498 $ 213,325 $ 386,705 Contract drilling 55,015
114,278 150,092 220,878 Gas gathering and processing 52,176
92,655 106,129 185,836
Total revenues 214,447 405,431
469,546 793,419 Expenses: Oil and
natural gas: Operating costs 45,972 44,723 91,183 85,138
Depreciation, depletion, and amortization 68,101 71,245 145,219
130,925 Impairment of oil and natural gas properties 410,536 —
811,129 — Contract drilling: Operating costs 36,485 66,494 88,231
130,298 Depreciation 13,265 20,239 28,278 38,634 Impairment of
contract drilling equipment 8,314 — 8,314 — Gas gathering and
processing: Operating costs 40,592 78,648 84,767 159,608
Depreciation and amortization 10,848 10,109 21,542 19,700 General
and administrative 9,624 10,600 18,994 20,237 Gain on disposition
of assets (415 ) (195 ) (960 ) (9,621 )
Total operating expenses 643,322 301,863
1,296,697 574,919 Income
(loss) from operations (428,875 ) 103,568
(827,151 ) 218,500 Other income
(expense): Interest, net (7,956 ) (4,131 ) (15,196 ) (7,921 ) Gain
(loss) on derivatives not designated as hedges (1,919 ) (10,709 )
4,667 (29,075 ) Other 24 (49 ) 22
71 Total other income (expense) (9,851
) (14,889 ) (10,507 ) (36,925 ) Income
(loss) before income taxes (438,726 ) 88,679 (837,658 ) 181,575
Income tax expense (benefit): Current 803 8,475 868 18,270
Deferred (165,140 ) 25,844 (315,783 )
52,000 Total income taxes (164,337 )
34,319 (314,915 ) 70,270 Net
income (loss) $ (274,389 ) $ 54,360 $ (522,743 ) $ 111,305
Net income (loss) per common share: Basic $ (5.58 ) $
1.12 $ (10.66 ) $ 2.29 Diluted $ (5.58 ) $ 1.11 $ (10.66 ) $ 2.27
Weighted average shares outstanding: Basic 49,148 48,642
49,063 48,568 Diluted 49,148 49,116 49,063 49,010
June 30, December 31,
2015 2014 Balance
Sheet Data: Current assets $ 166,534 $ 252,491 Total assets $
3,629,993 $ 4,473,728 Current liabilities $ 177,900 $ 304,171
Long-term debt $ 926,908 $ 812,163 Other long-term liabilities $
141,153 $ 148,785 Deferred income taxes $ 560,432 $ 876,215
Shareholders’ equity $ 1,823,600 $ 2,332,394
Six Months Ended June 30, 2015
2014 Statement of Cash Flows Data:
Cash flow from operations before changes in operating
assets and liabilities $ 207,221 $ 370,348 Net change in operating
assets and liabilities 50,385 (44,820 ) Net
cash provided by operating activities $ 257,606 $ 325,528
Net cash used in investing activities $ (366,442 ) $
(379,107 ) Net cash provided by financing activities $ 108,626
$ 36,064
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, 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 six months ended June 30, 2015
and 2014. 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
Earnings per Share Three Months Ended Six
Months Ended June 30, June 30, 2015
2014 2015 2014 (In
thousands except earnings per share) Adjusted net income: Net
income (loss) $ (274,389 ) $ 54,360 $ (522,743 ) $ 111,305
Impairment adjustment (net of income tax) 260,734 — 510,103 —
(Gain) loss on derivatives not designated as hedges (net of income
tax) 1,238 6,564 (2,786 ) 17,822 Settlements during the period of
matured derivative contracts (net of income tax) 6,495
(5,567 ) 13,223 (11,005 )
Adjusted net income (loss) $ (5,922 ) $ 55,357 $ (2,203 ) $
118,122 Adjusted diluted earnings per share: Diluted
earnings (loss) per share $ (5.58 ) $ 1.11 $ (10.66 ) $ 2.27
Diluted earnings per share from the impairments 5.31 — 10.40 —
Diluted earnings per share from the (gain) loss on derivatives 0.02
0.13 (0.06 ) 0.37 Diluted earnings (loss) per share from the
settlements of matured derivative contracts 0.13
(0.11 ) 0.27 (0.23 ) Adjusted diluted
earnings (loss) per share $ (0.12 ) $ 1.13 $ (0.05 ) $ 2.41
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.
Unit Corporation
Reconciliation of Average Daily Operating Margin Before
Elimination of Intercompany Rig Profit and Bad Debt Expense
Three Months Ended Six Months Ended March
31, June 30, June 30, 2015
2015 2014 2015
2014 (In thousands except for operating days and
operating margins) Contract drilling revenue $ 95,077 $ 55,015
$ 114,278 $ 150,092 $ 220,878 Contract drilling operating cost
51,746 36,485 66,494 88,231
130,298 Operating profit from contract drilling 43,331 18,530
47,784 61,861 90,580 Add: Elimination of intercompany rig profit
and bad debt expense 2,910 537 7,808
3,447 13,121 Operating profit from contract drilling before
elimination of intercompany rig profit and bad debt expense 46,241
19,067 55,592 65,308 103,701 Contract drilling operating days
4,510 2,795 6,684 7,305 12,797
Average daily operating margin before elimination of intercompany
rig profit and bad debt expense $ 10,253 $ 6,821 $ 8,317 $ 8,940 $
8,104
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 Operating Assets and
Liabilities
Six Months EndedJune 30,
2015 2014 (In thousands) Net
cash provided by operating activities $ 257,606 $ 325,528 Net
change in operating assets and liabilities (50,385 )
44,820 Cash flow from operations before changes in operating assets
and liabilities $ 207,221 $ 370,348
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.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20150804005488/en/
Unit CorporationMichael D. Earl, 918-493-7700Vice President,
Investor Relationswww.unitcorp.com
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