2012-11-07 23:17:17 -
Natchez, MS (November 7, 2012) - Callon Petroleum Company (NYSE: CPE)
("Callon" or the "Company") today reported results of operations for the
three-month period ended September 30, 2012.
The Company highlighted the recent operational activity and third quarter
financial results:
* Continued strong performance from the horizontal Wolfcamp B shale program,
with average daily production rates of 576 Boe per well on a 30-day basis.
* Initiated completion operations on the Vickie Newton 3801 #1H, a
horizontal well targeting the Cline shale and drilling of the Shirly
Newton 2301 #1H, a horizontal well targeting the Mississippian lime.
* Expanded the Company's Permian acreage position in the Midland Basin to
32,649 total net acres, adding 6,964 net acres in the northern Midland
Basin at an average price of $696 per acre since July 1, 2012.
* Revenue of $27.4 million from daily production of 4,337 barrels of oil
equivalent ("Boe") of production, or $68.67 per Boe produced.
* Net loss of $0.03 per share, which includes a $0.03 charge related to a
non-cash, mark-to-market of the Company's derivative positions.
* Discretionary cash flow, a non-GAAP financial measure, of $0.33 per
diluted share.
Fred Callon, Chairman and CEO commented, "Our production profile is beginning
to reflect the impact of our horizontal drilling program that we began earlier
this year. We produced over 2,100 Boe per day from our Permian operations
during the month of October, a 60% increase over our 2011 exit rate. In
addition to a total inventory of over 70 identified horizontal Wolfcamp shale
locations on our southern Midland Basin acreage, we are in the process of
evaluating two additional horizontal oil plays targeting the Cline shale and
Mississippian lime in the northern portion of the basin. These emerging plays
represent a potential catalyst for acceleration of our drilling activity in
the Permian beyond our foundation of horizontal Wolfcamp opportunities."
Drilling Activity Update
Southern Midland. Production from Callon's initial two horizontal wells
targeting the Wolfcamp B shale zone at its East Bloxom field in Upton County
has averaged 576 Boe per day (gross) over the first 30 days of hydrocarbon
production. Callon currently plans to recommence its drilling program in early
2013 at East Bloxom, targeting both the Wolfcamp A and Wolfcamp B shale zones.
The Company's third horizontal Wolfcamp B well, the Pembrook 9121H, is
scheduled to begin drilling in late November at the Taylor Draw field in
southern Reagan County.
Callon's vertical drilling program is currently focused on its Pecan Acres
field in Midland County and CH Ranch field in Glasscock County. Three wells in
Section 23 of the Pecan Acres field were completed in the third quarter and
are in the process of flowing back, and two additional wells are awaiting
completion. The Company will be evaluating the potential of deeper zones
within this package of wells, completing two wells below the Strawn interval.
At CH Ranch, one well targeting the Fusselman formation is awaiting completion
during the fourth quarter of 2012.
Northern Midland. Callon is currently completing the Vickie Newton #3801 which
is targeting the Cline shale in a lateral section totaling 6,679 feet. The
Company is also in the process of drilling the lateral portion of the Shirly
Newton 2301 #1H, a horizontal well targeting the Mississippian lime that is
currently expected to be completed in December 2012.
Deepwater Gulf of Mexico. The Habanero #2 sidetrack is scheduled to commence
drilling in December. In addition, Callon is continuing discussions with the
working interest partner group regarding future development drilling plans at
the Medusa field.
In 2013, Callon currently expects the Medusa field to be shut-in for 30 days
for modifications to the West Delta 143 pipeline system, and Habanero to be
shut-in for 74 days for both scheduled maintenance and the tie-in of the
Cardamom project to the Auger tension leg platform facility.
Summary Financial Results
Operating Revenues. Operating revenues for the three months ended September
30, 2012 include oil and natural gas sales of $27.4 million from average
production of 4,337 Boe per day. These results compare with oil and natural
gas sales of $33.6 million from average production of 5,261 Boe per day during
the comparable 2011 period.
Oil revenues decreased 9% to $24.1 million for the three months ended
September 30, 2012 compared to revenues of $26.5 million for the same period
of 2011. Contributing to the decrease in oil revenue was a 2% decrease in
commodity prices compounded by a 7% decrease in production. The average price
realized decreased to $95.86 per barrel compared to $98.27 for the same period
of 2011. Production decreased to 251 thousand barrels ("MBbls") during the
third quarter of 2012 compared to production of 270 MBbls during the same
period in 2011. The decrease in production was primarily attributable to
approximately 39 days of downtime at our Habanero field for scheduled
maintenance to the Auger Facility, combined with downtime at our Medusa and
Habanero fields attributable to Hurricane Isaac. Excluding the effect of this
downtime at our deepwater fields, oil production in the third quarter of 2012
compared to the same quarter of 2011 would have been relatively unchanged.
Further contributing to the decrease were the normal and expected declines in
production from our offshore properties. These production declines were offset
by increased production from our Permian operations.
Natural gas revenues of $3.3 million decreased 52% during the three months
ended September 30, 2012 as compared to natural gas revenues of $7.0 million
for the same period of 2011. Contributing to the decline was a 31% decrease in
the average price realized, which fell to $3.76 per thousand cubic feet of
natural gas ("Mcf") from $5.46 per Mcf, and a 31% decrease in natural gas
production, driven primarily by down time at our East Cameron 257 well, which
was suspended in the fourth quarter of 2011 due to a natural gas leak in an
upstream section of the Stingray Pipeline that transports production volumes
from the field. Production from our East Cameron 257 well is expected to
resume once the pipeline is brought back online during the first quarter of
2013. Excluding the effect of this downtime at East Cameron 257, natural gas
production decreases in the third quarter of 2012 compared to the same quarter
of 2011 would have been approximately 20%. Also, the downtime at our Habanero
and Medusa fields discussed previously, combined with normal and expected
declines in natural gas production from our other wells, contributed to the
period-to-period decline.
Our oil price realizations exceeded NYMEX prices by $3.64 per Bbl in the third
quarter of 2012 due to hedging impacts and the premium received on our
offshore production, partially offset by Permian Basin differentials and
transportation costs. Our natural gas price realizations on a million British
thermal unit ("MMBtu") equivalent basis exceeded the related NYMEX prices by
$0.86 per Mcf in the third quarter of 2012 primarily due to the value of the
natural gas liquids in our Permian Basin and offshore natural gas streams. On
a combined hydrocarbon equivalent basis, Callon received $68.67 per barrel of
oil equivalent produced for the third quarter of 2012.
Lease Operating Expenses. Lease operating expenses for the three months ended
September 30, 2012 were relatively unchanged at $5.9 million compared to $6.0
million for the same period in 2011. The decrease was primarily due to lower
deepwater property throughput charges related to reduced production volumes
from scheduled downtime and hurricane impacts, partially offset by cost
increases related to the significant growth in the number of wells now
producing on our Permian Basin properties.
General and Administrative Expenses. General and administrative expenses, net
of amounts capitalized, increased to $6.4 million for the three months ended
September 30, 2012 from $3.5 million for the same period of 2011. In addition
to the hiring of additional staff to support our growth initiatives, the
variance includes an increase of $2.1 million in the non-cash valuation
adjustment required to mark a portion of our share-based awards to fair value
and non-recurring additional employee-related costs, including early
retirement expense, of $0.5 million.
Interest Expense. Interest expense on our debt obligations decreased 22% to
$2.1 million for the three months ended September 30, 2012 compared to $2.7
million for the same period of 2011. The decrease relates to the redemption of
$10.0 million principal of Senior Notes during June 2012 in addition to a $0.5
million increase in capitalized interest compared to 2011, partially offset by
interest expense related to an increase in bank borrowings.
Net Income. For the three months ended September 30, 2012, the Company
reported a net loss of $1.1 million and $0.03 per share, compared to net
income and diluted earnings per share of $8.4 million and $0.21, respectively
for the same period of 2011. Included in the three months ended September
30, 2012 was an after-tax loss of $1.1 million and $0.03 per share related to
a mark-to-market of the Company's derivative positions.
Discretionary Cash Flow. Discretionary cash flow for the three months ended
September 30, 2012 totaled $13.0 million compared to $20.0 million during the
comparable prior year period. Net cash flow provided by operating activities,
as defined by U.S. GAAP, was $13.9 million for the three months ended
September 30, 2012, and $27.0 million for the comparable prior year period.
(See "Non-GAAP Financial Measures" that follows and the accompanying
reconciliation of discretionary cash flow, a non-GAAP measure, to net cash
flow provided by operating activities.)
Capital Expenditures. Callon's total capital expenditures for the nine months
ended September 30, 2012 were $115.4 million and included the following
amounts (in millions):
Southern Midland Basin $ 57.9
Northern Midland Basin 11.1
Leasehold acquisitions 34.4
Gulf of Mexico 1.5
Capitalized general and administrative and interest expenses 10.5
----------
Total capital expenditures $ 115.4
----------
The following table summarizes drilled and completed wells through
September 30, 2012:
Drilling Completion
---------------- ---------------
Gross Net Gross Net
------- -------- ------- -------
Southern Midland Basin vertical wells 15 10.7 19 14.8
Southern Midland Basin horizontal wells 2 2.0 2 2.0
Northern Midland Basin vertical wells 1 0.8 0 0.0
Northern Midland Basin horizontal wells 1 1.0 0 0.0
------- -------- ------- -------
Total 19 14.5 21 16.8
------- -------- ------- -------
Liquidity. At November 1, 2012, the Company's total liquidity position was
$37.5 million comprised of a cash balance of $1.5 million and borrowing
availability of $36.0 million under its revolving credit facility with a
current borrowing base of $80.0 million that was established in October 2012.
Third Quarter 2012 Conference Call
A conference call to discuss this release has been scheduled for Thursday,
November 8, 2012 at 1:00 pm CDT. The telephone number to access the conference
call is 1-877-317-6789 (toll-free). The conference call will also be webcast
live on the Internet, and can be accessed by accessing Callon's website at
www.callon.com in the "Investors" section of the website. A Q&A period will
follow.
An archive of the conference call webcast will also be available at
www.callon.com in the "Investors" section of the website.
Non-GAAP Financial Measures. This news release refers to non-GAAP financial
measures as "discretionary cash flow". Callon believes that the non-GAAP
measure of discretionary cash flow is useful as an indicator of an oil and gas
exploration and production company's ability to internally fund exploration
and development activities and to service or incur additional debt. The
Company also has included this information because changes in operating assets
and liabilities relate to the timing of cash receipts and disbursements which
the company may not control and may not relate to the period in which the
operating activities occurred.
Reconciliation of Non-GAAP Financial Measures:
The following table reconciles discretionary cash flow to net cash flow
provided by operating activities (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- -------------------
2012 2011 Change 2012 2011 Change
---------- ---------- ----------- --------- --------- ----------
Discretionary $12,960 $19,989 ($7,029) $38,595 $56,996 ($18,401)
cash flow
Net working
capital 984 6,982 (5,998) 2,790 933 1,857
changes and
other changes
---------- ---------- ----------- --------- --------- ----------
Net cash flow $13,944 $26,971 ($13,027) $41,385 $57,929 ($16,544)
provided by
(used in)
operating
activities
---------- ---------- ----------- --------- --------- ----------
Discretionary $12,960
cash flow
Weighted 39,575
average shares
outstanding
for diluted
net income
(loss) per
share
Discretionary $0.33
cash flow per
diluted share
Other Financial and Operational Tables:
Three Months Ended September 30,
------------------------------------------------
2012 2011 Change %
Change
------------ ------------ ------------ ---------
Net production:
Crude oil (MBbls) 251 270 (19 ) (7 )%
Natural gas (MMcf) 890 1,284 (394 ) (31 )%
Total production (MBoe) 399 484 (85 ) (18 )%
Average daily production 4.3 5.3 (0.9 ) (17 )%
(MBoe)
Average realized sales price
(a):
Crude oil (Bbl) $ 95.86 $ 98.27 $ (2.41 ) (2 )%
Natural gas (Mcf) $ 3.76 $ 5.46 $ (1.70 ) (31 )%
Total on an equivalent basis $ 68.67 $ 69.31 $ (0.64 ) (1 )%
(Boe)
Crude oil and natural gas
revenues (in thousands):
Crude oil revenue $ 24,061 $ 26,537 $ (2,476 ) (9 )%
Natural gas revenue 3,341 7,013 (3,672 ) (52 )%
------------ ------------ ------------
Total $ 27,402 $ 33,550 $ (6,148 ) (18 )%
------------ ------------ ------------
Additional per Boe data:
Sales price $ 68.67 $ 69.31 $ (0.64 ) (1 )%
Lease operating expense 14.69 12.35 2.34 19 %
------------ ------------ ------------
Operating margin $ 53.98 $ 56.96 $ (2.98 ) (5 )%
------------ ------------ ------------
Other expenses per Boe:
Depletion, depreciation and $ 29.99 $ 26.88 $ 3.11 12 %
amortization
General and administrative 16.14 7.16 8.98 125 %
(a) Below is a reconciliation of the average NYMEX price to the average
realized sales price:
Average NYMEX price per $ 92.22 $ 89.78 $ 2.44 3 %
barrel of crude oil
Basis differential and 3.28 9.10 (5.82 ) (64 )%
quality adjustments
Transportation (0.68 ) (0.94 ) 0.26 (28 )%
Hedging 1.04 0.33 0.71 215 %
------------ ------------ ------------
Average realized price per $ 95.86 $ 98.27 $ (2.41 ) (2 )%
barrel of crude oil
------------ ------------ ------------
Average NYMEX price per $ 2.90 $ 4.29 $ (1.39 ) (32 )%
million British thermal
units ("MMBtu")
Basis differential, quality 0.86 1.17 (0.31 ) (26 )%
and Btu adjustments
Hedging - - - - %
------------ ------------ ------------
Average realized price per $ 3.76 $ 5.46 $ (1.7 ) (31 )%
Mcf of natural gas
------------ ------------ ------------
Nine Months Ended September 30,
-------------------------------------------------
2012 2011 Change %
Change
------------ ------------ ------------- ---------
Net production:
Crude oil (MBbls) 716 746 (30 ) (4 )%
Natural gas (MMcf) 2,695 4,014 (1,318 ) (33 )%
Total production (MBoe) 1,165 1,415 (250 ) (18 )%
Average daily production 4.3 5.2 (0.9 ) (17 )%
(MBoe)
Average realized sales
price (a):
Crude oil (Bbl) $ 100.39 $ 99.82 $ 0.57 1 %
Natural gas (Mcf) $ 3.77 $ 5.33 $ (1.56 ) (29 )%
Total on an equivalent $ 70.44 $ 67.75 $ 2.69 4 %
basis (Boe)
Crude oil and natural gas
revenues (in thousands):
Crude oil revenue $ 71,883 $ 74,428 $ (2,545 ) (3 )%
Natural gas revenue 10,174 21,404 (11,230 ) (52 )%
------------ ------------ -------------
Total $ 82,057 $ 95,832 $ (13,775 ) (14 )%
------------ ------------ -------------
Additional per Boe data:
Sales price $ 70.44 $ 67.75 $ 2.69 4 %
Lease operating expense 17.57 11.54 6.03 52 %
------------ ------------ -------------
Operating margin $ 52.87 $ 56.21 $ (3.34 ) (6 )%
------------ ------------ -------------
Other expenses per Boe:
Depletion, depreciation $ 30.90 $ 25.27 $ 5.63 22 %
and amortization
General and administrative 13.60 8.12 5.48 67 %
(a) Below is a reconciliation of the average NYMEX price to the average
realized sales price:
Average NYMEX price per $ 96.21 $ 95.48 $ 0.73 1 %
barrel of crude oil
Basis differential and 3.84 5.84 (2.00 ) (34 )%
quality adjustments
Transportation (0.74 ) (1.02 ) 0.28 (27 )%
Hedging 1.08 (0.48 ) 1.56 (325 )%
------------ ------------ -------------
Average realized price per $ 100.39 $ 99.82 $ 0.57 1 %
barrel of crude oil
------------ ------------ -------------
Average NYMEX price per $ 2.43 $ 4.29 $ (1.86 ) (43 )%
million British thermal
units ("MMBtu")
Basis differential, 1.34 1.04 0.30 29 %
quality and Btu
adjustments
Hedging - - - - %
------------ ------------ -------------
Average realized price per $ 3.77 $ 5.33 $ (1.56 ) (29 )%
Mcf of natural gas
------------ ------------ -------------
September 30, December 31,
2012 2011
----------------- ---------------
ASSETS Unaudited
Current assets:
Cash and cash equivalents $ 1,485 $ 43,795
Accounts receivable 16,643 15,181
Fair market value of derivatives 2,013 2,499
Other current assets 1,359 1,601
----------------- ---------------
Total current assets 21,500 63,076
----------------- ---------------
Oil and natural gas properties, full-cost
accounting method:
Evaluated properties 1,490,862 1,421,640
Less accumulated depreciation, depletion and (1,244,329 ) (1,208,331 )
amortization
----------------- ---------------
Net oil and natural gas properties 246,533 213,309
Unevaluated properties excluded from 45,672 2,603
amortization
----------------- ---------------
Total oil and natural gas properties 292,205 215,912
----------------- ---------------
Other property and equipment, net 12,374 10,512
Restricted investments 3,796 3,790
Investment in Medusa Spar LLC 8,809 9,956
Deferred tax asset 64,911 65,744
Other assets, net 2,004 717
----------------- ---------------
Total assets $ 405,599 $ 369,707
----------------- ---------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 30,988 $ 26,057
Asset retirement obligations 2,340 1,260
Fair market value of derivatives 224 -
----------------- ---------------
Total current liabilities 33,552 27,317
----------------- ---------------
13% Senior Notes:
Principal outstanding 96,961 106,961
Deferred credit, net of accumulated 14,489 18,384
amortization of $17,018 and $13,123,
respectively
----------------- ---------------
Total 13% Senior Notes 111,450 125,345
----------------- ---------------
Senior secured revolving credit facility 40,000 -
Asset retirement obligations 11,664 12,678
Other long-term liabilities 3,471 3,164
----------------- ---------------
Total liabilities 200,137 168,504
----------------- ---------------
Stockholders' equity:
Preferred Stock, $0.01 par value, 2,500 - -
shares authorized;
Common stock, $0.01 par value, 60,000 shares 398 394
authorized; 39,780 and 39,398 shares
outstanding at September 30, 2012 and
December 31, 2011, respectively
Capital in excess of par value 326,892 324,474
Other comprehensive income 279 1,624
Retained deficit (122,107 ) (125,289 )
----------------- ---------------
Total stockholders' equity 205,462 201,203
----------------- ---------------
Total liabilities and stockholders' equity $ 405,599 $ 369,707
----------------- ---------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- ------------------------
2012 2011 2012 2011
------------ ------------ ------------ -----------
Operating revenues:
Crude oil revenues $ 24,061 $ 26,537 $ 71,883 $ 74,428
Natural gas revenues 3,341 7,013 10,174 21,404
------------ ------------ ------------ -----------
Total oil and natural gas 27,402 33,550 82,057 95,832
revenues
Operating expenses:
Lease operating expenses 5,859 5,980 20,465 16,324
Depreciation, depletion 11,965 13,013 35,998 35,741
and amortization
General and administrative 6,441 3,464 15,846 11,487
Accretion expense 574 569 1,709 1,767
------------ ------------ ------------ -----------
Total operating expenses 24,839 23,026 74,018 65,319
------------ ------------ ------------ -----------
Income from operations 2,563 10,524 8,039 30,513
------------ ------------ ------------ -----------
Other (income) expenses:
Interest expense 2,135 2,722 7,096 8,912
Gain on early - - (1,366 ) (1,942 )
extinguishment of debt
Gain on acquired assets - (46 ) - (5,025 )
Unrealized loss (gain) on 1,598 - (1,977 ) -
mark-to-market derivative
instruments, net
Other (income) expense 237 (347 ) (224 ) (599 )
------------ ------------ ------------ -----------
Total other (income) 3,970 2,329 3,529 1,346
expenses
------------ ------------ ------------ -----------
Income (loss) before (1,407 ) 8,195 4,510 29,167
income taxes
Income tax expense (246 ) - 1,508 (2,681 )
(benefit)
------------ ------------ ------------ -----------
Income (loss) before (1,161 ) 8,195 3,002 31,848
equity in earnings of
Medusa Spar LLC
Equity in earnings of 56 211 180 597
Medusa Spar LLC
------------ ------------ ------------ -----------
Net income (loss) $ (1,105 ) $ 8,406 $ 3,182 $ 32,445
available to common shares
------------ ------------ ------------ -----------
Net income (loss) per
common share:
Basic $ (0.03 ) $ 0.21 $ 0.08 $ 0.87
Diluted $ (0.03 ) $ 0.21 $ 0.08 $ 0.85
Shares used in computing
net income (loss) per
common share:
Basic 39,575 39,322 39,441 37,431
Diluted 39,575 39,976 40,243 38,120
Nine Months Ended
September 30,
---------------------------
2012 2011
-------------- ------------
Cash flows from operating activities:
Net income $ 3,182 $ 32,445
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion and amortization 37,005 36,501
Accretion expense 1,709 1,767
Non-cash gain on acquired assets - (4,979 )
Amortization of non-cash debt related items 293 338
Amortization of deferred credit (2,304 ) (2,361 )
Non-cash gain on early extinguishment of debt (1,366 ) (1,942 )
Equity in earnings of Medusa Spar LLC (180 ) (597 )
Deferred income tax expense 1,508 11,987
Valuation allowance - (14,668 )
Non-cash derivative income due to hedge (40 ) (189 )
ineffectiveness
Non-cash unrealized gain on mark-to-market (1,977 ) -
derivative instruments, net
Non-cash charge related to compensation plans 1,901 1,122
Payments to settle asset retirement obligations (1,136 ) (2,428 )
Changes in current assets and liabilities:
Accounts receivable (1,260 ) (5,280 )
Other current assets 244 37
Current liabilities 4,965 6,334
Change in natural gas balancing receivable (96 ) 198
Change in natural gas balancing payable (152 ) (29 )
Change in other long-term liabilities - 100
Change in other assets, net (911 ) (427 )
-------------- ------------
Cash provided by operating activities $ 41,385 $ 57,929
-------------- ------------
Cash flows from investing activities:
Capital expenditures (115,401 ) (74,388 )
Investment in restricted assets for plugging and - (112 )
abandonment
Proceeds from sale of mineral interest and 526 7,559
equipment
Distribution from Medusa Spar LLC 1,423 1,107
-------------- ------------
Cash used in investing activities $ (113,452 ) $ (65,834 )
-------------- ------------
Cash flows from financing activities:
Draw on senior secured credit facility 43,000 -
Payments on senior secured credit facility (3,000 ) -
Redemption of 13% senior notes (10,225 ) (35,062 )
Issuance of common stock - 73,765
Equity issued related to employee stock plans (18 ) -
-------------- ------------
Cash provided by financing activities $ 29,757 $ 38,703
-------------- ------------
Net change in cash and cash equivalents (42,310 ) 30,798
Beginning of period cash and cash equivalents 43,795 17,436
-------------- ------------
End of period cash and cash equivalents $ 1,485 $ 48,234
-------------- ------------
Callon Petroleum Company is engaged in the acquisition, development, exploration
and operation of oil and gas properties in Texas, Louisiana and the offshore
waters of the Gulf of Mexico.
This news release is posted on the Company`s website at www.callon.com and will
be archived there for subsequent review. It can be accessed from the "News
Releases" link on the top of the homepage.
This news release contains projections forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Forward-looking statements include all
statements regarding our reserves, the timing of drilling and completion
activities, and estimates of the duration of scheduled downtime of offshore
production, as well as statements including the words "believe,"
"expect,"
"plans" and words of similar meaning. These projections and statements reflect
the Company's current views with respect to future events and financial
performance. No assurances can be given, however, that these events will occur
or that these projections will be achieved, and actual results could differ
materially from those projected as a result of certain factors. Some of the
factors which could affect our future results and could cause results to differ
materially from those expressed in our forward-looking statements are discussed
in our filings with the Securities and Exchange Commission, including our Annual
Reports on Form 10-K, available on our website or the SEC`s website at
www.sec.gov.
For further information contact
Rodger W. Smith, 1-800-451-1294
This announcement is distributed by Thomson Reuters on behalf of
Thomson Reuters clients. The owner of this announcement warrants that:
(i) the releases contained herein are protected by copyright and
other applicable laws; and
(ii) they are solely responsible for the content, accuracy and
originality of the information contained therein.
Source: Callon Petroleum Company via Thomson Reuters ONE
[HUG#1655173]
