CALLON PETROLEUM COMPANY NATCHEZ, Miss., Nov. 6, 2017 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months ended September 30, 2017.
Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located on the "Presentations" page within the Investors section of the site.
Financial and operational highlights for the third quarter of 2017, and other recent data points include:
-- Increased production by 36% year-over-year, with an increased percentage
of oil volumes
-- Reduced lease operating expense by 9% on a sequential basis to $5.08 per
BOE, contributing to a total reduction of 23% since the first quarter of
2017
-- Generated a third quarter operating margin of $32.58 per BOE
-- First operated Delaware Basin Lower Wolfcamp A well had a 24 hour peak
flowing rate of 238 BOE/d per 1,000' (82% oil)
-- Successful return to Ranger drilling program with two Lower Wolfcamp B
wells outperforming previous type curves
Joe Gatto, Chief Executive Officer and President commented, "This quarter's results speak to our team's commitment to generating strong returns by focusing on driving down costs while extracting the best well results possible from our premier asset base. Consistent improvement in our already strong cash margins, despite production deferrals during the quarter, is evidence that we are taking the correct steps to create shareholder value. Our goal is to manage growth as a function of creating returns on our capital investment. We have been consistent in our focus on these priorities and will continue to be into 2018." He continued, "Callon's well results were strong across all four of our operations areas during the third quarter, including our first operated well in the Delaware Basin. Early well results in the fourth quarter have been equally strong and we are excited about our prospects for 2018."
Operations Update
At September 30, 2017, we had 218 gross (161.2 net) horizontal wells producing from seven established flow units in the Permian Basin. Net daily production for the three months ended September 30, 2017 grew approximately 36% to 22.5 thousand barrels of oil equivalent per day (approximately 77% oil) as compared to the same period of 2016.
For the three months ended September 30, 2017, we operated four horizontal drilling rigs, drilling 13 gross (10.3 net) horizontal wells in the Spur, WildHorse, Ranger and Monarch areas. We placed a combined 11 gross (10.1 net) horizontal wells on production in the quarter in these areas.
In the Delaware Basin, we drilled and completed our first operated Lower Wolfcamp A well, the Sleeping Indian A1 #1LA well. The well is currently outperforming the 7,500 foot type curve, with an oil cut of approximately 82%. We recently completed our second operated well, the Saratoga A1 #7LA and have placed the well on flowback. We expect to commence multi-well pad development prior to the end of this year with co-development of the Upper and Lower Wolfcamp A.
In the Midland Basin, we were active across all three focus areas: WildHorse, Ranger and Monarch. In Howard County at our WildHorse area, we placed multiple Wolfcamp A wells on production during the second half of the quarter. The wells are cleaning up and have shown similar productivity to our previous wells in the area on an early time basis. Our plans are to continue program development of multiple zones across our footprint and we also expect to test tighter Wolfcamp A spacing, at 10 wells per section, in 2018.
In Reagan County at our Ranger area, our first operated Lower Wolfcamp B wells since 2015 are outperforming the type curve by more than 20%. During the quarter, we drilled our first Wolfcamp C well in this area, which is scheduled for completion during the fourth quarter along with two additional Lower Wolfcamp B wells. We currently do not account for any Wolfcamp C locations in our delineated inventory.
At our Monarch area in Midland County, we drilled a three-well pad consisting of our longest wells to date at an average of over 21,000 feet true measured depth. The completed lateral length for these wells averaged approximately 10,600 feet and the wells are entering their fourth week of flowback.
Infrastructure investment continued to be a key focus in the third quarter. We realized an impressive reduction in lease operating expenses this quarter, and we expect this infrastructure investment to continue to improve operating margins as well as position Callon as an environmentally-responsible operator for the long term. We continued to invest in saltwater disposal wells in the Midland Basin and Delaware Basin, resulting in increased disposal capacity and reduced disposal costs. In addition, we have begun utilizing recycled water volumes in the Midland Basin and are currently preparing infrastructure at our Spur asset to implement water recycling for our planned two rig program in 2018. Importantly, after developing a substantial base of Callon-owned infrastructure, we are now positioned to selectively monetize portions of our asset base while ensuring reliable operations. As an initial step in this initiative, we expect to complete at least $20 million of such transactions in the fourth quarter, with other identified transactions expected to close by the end of the first quarter of 2018.
Capital Expenditures
For the three months ended September 30, 2017, we incurred $112.7 million in cash operational capital expenditures (excluding other items) compared to $64.0 million in the second quarter of 2017. Total capital expenditures,
inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):
Three Months Ended September 30, 2017
Operational Capitalized Capitalized Total Capital
Capital Other (a) Interest G&A Expenditures
------- -------- -------- --- ------------
Cash basis (b) $112,667 $3,767 $479 $4,215 $121,128
Timing adjustments (c) 711 - 9,119 - 9,830
Non-cash items - - - 1,133 1,133
Accrual (GAAP) basis $113,378 $3,767 $9,598 $5,348 $132,091
======== ====== ====== ====== ========
(a) Includes seismic, land and other
items.
(b) Cash basis is a non-GAAP measure
that we believe helps users of the
financial information reconcile
amounts to the cash flow statement
and to account for timing related
operational changes such as our
development pace and rig count.
(c) Includes timing adjustments related
to cash disbursements in the
current period for capital
expenditures incurred in the prior
period.
Operating and Financial Results
The following table presents summary information for the periods indicated:
Three Months Ended
September 30, June 30, 2017 September 30,
2017 2016
-------------- ------------- --------------
Net production:
Oil (MBbls) 1,591 1,596 1,153
Natural gas (MMcf) 2,900 2,550 2,244
Total production (MBOE) 2,074 2,021 1,527
Average daily production
(BOE/d) 22,543 22,209 16,598
% oil (BOE basis) 77% 79% 76%
Oil and natural gas
revenues (in thousands):
Oil revenue $73,349 $72,885 $49,095
Natural gas revenue 11,265 9,398 6,832
Total revenue 84,614 82,283 55,927
Impact of cash-settled
derivatives (1,214) (267) 4,091
Adjusted Total Revenue
(i) $83,400 $82,016 $60,018
======= ======= =======
Average realized sales
price:
Oil (Bbl) (excluding
impact of cash settled
derivatives) $46.10 $45.67 $42.58
Oil (Bbl) (including
impact of cash settled
derivatives) 45.24 45.47 46.27
Natural gas (Mcf)
(excluding impact of
cash settled
derivatives) $3.88 $3.69 $3.04
Natural gas (Mcf)
(including impact of
cash settled
derivatives) 3.94 3.70 2.97
Total (BOE) (excluding
impact of cash settled
derivatives) $40.80 $40.71 $36.63
Total (BOE) (including
impact of cash settled
derivatives) 40.21 40.58 39.30
Additional per BOE data:
Sales price (excluding
impact of cash settled
derivatives) $40.80 $40.71 $36.63
Lease operating expense
(excluding gathering and
treating
expense) 5.08 5.56 6.16
Gathering and treating
expense 0.52 0.45 0.36
Production taxes 2.62 2.38 2.28
Operating margin $32.58 $32.32 $27.83
====== ====== ======
Depletion, depreciation
and amortization $13.75 $12.97 $11.33
Adjusted G&A (a)
Cash component (b) $2.50 $2.67 $2.38
Non-cash component 0.65 0.53 0.58
(a) Excludes certain non-recurring
expenses and non-cash valuation
adjustments. See the
reconciliation provided within
this press release for a
reconciliation of G&A expense on
a GAAP basis to Adjusted G&A
expense.
(b) Excludes the amortization of
equity-settled share-based
incentive awards and corporate
depreciation and amortization.
Total Revenue. For the quarter ended September 30, 2017, Callon reported total revenue of $84.6 million and total revenue including cash-settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure((i))) of $83.4 million, including the impact of a $1.2 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company's revenue. Average daily production for the quarter was 22.5 MBOE/d compared to average daily production of 22.2 MBOE/d in the second quarter of 2017. Average realized prices, including and excluding the effects of hedging, are detailed below.
Hedging impacts. For the quarter ended September 30, 2017, Callon recognized the following hedging-related items (in thousands, except per unit data):
In Thousands Per Unit
------------ --------
Oil derivatives
Net loss on settlements $(1,373) $(0.86)
Net loss on fair value
adjustments (12,811)
Total loss on oil derivatives $(14,184)
========
Natural gas derivatives
Net gain on settlements $159 $0.06
Net loss on fair value
adjustments (137)
Total gain on natural gas
derivatives $22
===
Total oil & natural gas
derivatives
Net loss on settlements $(1,214) $(0.59)
Net loss on fair value
adjustments (12,948)
Total loss on total oil &
natural gas derivatives $(14,162)
========
Lease Operating Expenses, including workover and gathering expense ("LOE"). LOE per BOE for the three months ended September 30, 2017 was $5.60 per BOE, compared to LOE of $6.01 per BOE in the second quarter of 2017. The decrease in this metric resulted primarily from a decrease in the number of workovers period over period.
Production Taxes, including ad valorem taxes. Production taxes were $2.62 per BOE for the three months ended September 30, 2017, representing approximately 6.4% of total revenue before the impact of derivative settlements.
Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended September 30, 2017 was $13.75 per BOE compared to $12.97 per BOE in the second quarter of 2017. The increase on a per unit basis was primarily attributable to greater increases in our depreciable asset base and assumed future development costs related to undeveloped proved reserves as compared to the estimated total proved reserve base.
General and Administrative ("G&A"). G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A", a non-GAAP measure((i))) was $6.5 million, or $3.15 per BOE, for the three months ended September 30, 2017 compared to $6.5 million, or $3.20 per BOE, for the second quarter of 2017. The cash component of Adjusted G&A was $5.2 million, or $2.50 per BOE, for the three months ended September 30, 2017 compared to $5.4 million, or $2.67 per BOE, for the second quarter of 2017.
For the three months ended September 30, 2017, G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands):
Three Months Ended
September 30, 2017
------------------
Total G&A expense $7,259
Less: Change in the fair value of
liability share-based awards
(non-cash) (731)
----
Adjusted G&A - total 6,528
Less: Restricted stock share-based
compensation (non-cash) (1,198)
Less: Corporate depreciation &
amortization (non-cash) (146)
Adjusted G&A - cash component $5,184
======
Income tax expense. Callon typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. We recorded an income tax expense of $0.2 million for the three months ended September 30, 2017 which relates to deferred State of Texas gross margin tax. At September 30, 2017 we had a valuation allowance of $109.8 million. Adjusted Income per fully diluted common share, a non-GAAP financial measure((i)), adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision of $6.1 million (or $0.03 per diluted share) for the quarter as if the valuation allowance did not exist.
2017 Guidance Update
Fourth Quarter
2017 Guidance
-------------
Total production (BOE/d) 24,000 - 25,500
% oil 77 %
Income Statement Expenses (per BOE)
LOE, including workovers $5.75 - $6.25
Gathering and treating $0.55 - $0.65
Production taxes, including ad
valorem (% unhedged revenue) 7%
Adjusted G&A: cash component (a) $2.25 - $2.50
Adjusted G&A: non-cash component
(b) $0.55 - $0.65
Interest expense (c) $0.00
Effective income tax rate 0%
Capital expenditures ($MM, accrual
basis)
Total Operational (net of
monetizations) (d) $108 - $112 ($88 - $92)
Capitalized expenses (cash
component) $13 - $17
Net operated horizontal well
completions
Midland Basin ~12
Delaware Basin ~1
(a) Excludes stock-based compensation
and corporate depreciation and
amortization. See the Non-GAAP
related disclosures referenced in
the footnote (b) below.
(b) Excludes certain non-recurring
expenses and non-cash valuation
adjustments. The reconciliation
above provides a reconciliation of
third quarter 2017 G&A expense on
a GAAP basis to Adjusted G&A
expense, a non-GAAP measure. The
Company is unable to present a
quantitative reconciliation of
this forward-looking non-GAAP
financial measure without
unreasonable effort because of the
number of estimated variables that
could affect the final value.
Accordingly, investors are
cautioned not to place undue
reliance on this information.
(c) All interest expense anticipated to
be capitalized.
(d) Includes seismic, land and other
items. Excludes capitalized
expenses.
Hedge Portfolio Summary
The following tables summarize our open derivative positions for the
periods indicated:
For the For the Full
Remainder of Year of
Oil contracts (WTI) 2017 2018
-------------------------------- ---- ----
Swap contracts
combined with
short puts
(enhanced
swaps)
Total volume (MBbls) 184 -
Weighted
average price
per Bbl
Swap $44.50 $ -
Short put option $30.00 $ -
Swap contracts
Total volume (MBbls) 184 1,825
Weighted average price per Bbl $45.74 $51.42
Deferred
premium put
spread option
Total volume (MBbls) 253 -
Premium per Bbl $2.45 $ -
Weighted
average price
per Bbl
Long put option $50.00 $ -
Short put option $40.00 $ -
Collar
contracts
(two-way
collars)
Total volume (MBbls) 340 -
Weighted
average price
per Bbl
Ceiling (short call) $58.19 $ -
Floor (long put) $47.50 $ -
Call option
contracts
Total volume (MBbls) 169 -
Premium per Bbl $1.82 $ -
Weighted
average price
per Bbl
Short call strike price (a) $50.00 $ -
Long call strike price (a) $50.00 $ -
Collar
contracts
combined with
short puts
(three-way
collars)
Total volume (MBbls) - 3,468
Weighted
average price
per Bbl
Ceiling (short call option) $ - $60.86
Floor (long put option) $ - $48.95
Short put option $ - $39.21
(a) Offsetting contracts.
For the For the Full
Remainder of Year of
Oil contracts
(Midland basis
differential) 2017 2018
--------------- ---- ----
Swap contracts
Volume (MBbls) 552 5,109
Weighted average
price per Bbl $(0.52) $(0.90)
For the For the Full
Remainder Year of
of
Natural gas contracts (Henry
Hub) 2017 2018
---------------------------- ---- ----
Collar contracts combined
with short puts (three-way
collars)
Total volume (BBtu) 368 -
Weighted average price per
MMBtu
Ceiling (short call option) $3.71 $ -
Floor (long put option) $3.00 $ -
Short put option $2.50 $ -
Collar contracts (two-way
collars)
Total volume (BBtu) 856 720
Weighted average price per
MMBtu
Ceiling (short call option) $3.77 $3.84
Floor (long put option) $3.23 $3.40
Swap contracts
Total volume (BBtu) 124 -
Weighted average price per
MMBtu $3.39 $ -
Income (Loss) Available to Common Shareholders. The Company reported net income available to common shareholders of $15.3 million for the three months ended September 30, 2017 and Adjusted Income available to common shareholders of $18.1 million, or $0.09 per diluted share. Adjusted Income per fully diluted common share, a non-GAAP financial measure((i)), adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision for the quarter as if the valuation allowance did not exist. The following tables reconcile to the related GAAP measure the Company's income (loss) available to common stockholders to Adjusted Income and the Company's net income (loss) to Adjusted EBITDA (in thousands):
Three Months Ended
September 30, June 30, 2017 September 30,
2017 2016
-------------- ------------- --------------
Income available to
common stockholders $15,257 $31,566 $19,315
Change in valuation
allowance (6,064) (11,194) (7,907)
Net (gain) loss on
derivatives, net of
settlements 8,416 (6,995) (679)
Change in the fair
value of share-
based awards 475 (315) 2,192
Settled share-based
awards - 4,128 -
Adjusted Income $18,084 $17,190 $12,921
======= ======= =======
Adjusted Income per
fully diluted
common share $0.09 $0.09 $0.09
===== ===== =====
Three Months Ended
September 30, June 30, 2017 September 30,
2017 2016
-------------- ------------- --------------
Net income $17,081 $33,390 $21,139
Net (gain) loss on
derivatives, net of
settlements 12,947 (10,761) (1,044)
Non-cash stock-
based compensation
expense 1,952 499 4,150
Settled share-based
awards - 6,351 -
Acquisition expense 205 2,373 456
Income tax (benefit)
expense 237 322 (62)
Interest expense 444 589 831
Depreciation,
depletion and
amortization 29,132 26,765 17,733
Accretion expense 131 208 187
---
Adjusted EBITDA $62,129 $59,736 $43,390
======= ======= =======
Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure((i)), for the three months ended September 30, 2017 was $61.9 million and is reconciled to operating cash flow in the following table (in thousands):
Three Months Ended
September 30, June 30, 2017 September 30,
2017 2016
-------------- ------------- --------------
Cash flows from operating
activities:
Net income $17,081 $33,390 $21,139
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation,
depletion and
amortization 29,132 26,765 17,733
Accretion expense 131 208 187
Amortization of
non-cash debt
related items 441 589 810
Deferred income
tax expense 237 323 (62)
Net (gain) loss on
derivatives, net
of settlements 12,947 (10,761) (1,044)
Loss on sale of
other property
and equipment - 62 -
Non-cash expense
related to equity
share-based
awards 1,219 4,865 608
Change in the fair
value of
liability share-
based awards 732 1,982 3,371
Discretionary cash
flow $61,920 $57,423 $42,742
======= ======= =======
Changes in working
capital $(7,777) $(8,968) $2,927
Payments to settle
asset retirement
obligations (250) (816) (576)
Payments to settle
vested liability
share-based
awards - (4,511) -
Net cash provided
by operating
activities $53,893 $43,128 $45,093
======= ======= =======
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)
September 30, 2017 December 31, 2016
------------------ -----------------
ASSETS Unaudited
Current assets:
Cash and cash equivalents $61,609 $652,993
Accounts receivable 81,973 69,783
Fair value of derivatives 3,333 103
Other current assets 2,583 2,247
Total current assets 149,498 725,126
------- -------
Oil and natural gas properties, full cost
accounting method:
Evaluated properties 3,283,985 2,754,353
Less accumulated depreciation,
depletion, amortization and
impairment (2,026,809) (1,947,673)
---------- ----------
Net evaluated oil and natural
gas properties 1,257,176 806,680
Unevaluated properties 1,173,614 668,721
Total oil and natural gas
properties 2,430,790 1,475,401
--------- ---------
Other property and equipment,
net 18,626 14,114
Restricted investments 3,362 3,332
Deferred financing costs 5,209 3,092
Fair value of derivatives 1,121 -
Acquisition deposit - 46,138
Prepaid 4,650 -
Other assets, net 827 384
Total assets $2,614,083 $2,267,587
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued
liabilities $147,338 $95,577
Accrued interest 18,375 6,057
Cash-settleable restricted
stock unit awards 4,158 8,919
Asset retirement obligations 1,841 2,729
Fair value of derivatives 6,380 18,268
Total current liabilities 178,092 131,550
------- -------
Senior secured revolving credit
facility - -
6.125% senior unsecured notes
due 2024, net of unamortized
deferred financing costs 595,115 390,219
Asset retirement obligations 3,163 3,932
Cash-settleable restricted
stock unit awards 2,626 8,071
Deferred tax liability 1,158 90
Fair value of derivatives 659 28
Other long-term liabilities 405 295
Total liabilities 781,218 534,185
------- -------
Commitments and contingencies
Stockholders' equity:
Preferred stock, series A
cumulative, $0.01 par value
and $50.00 liquidation
preference, 2,500,000 shares
authorized; 1,458,948 shares
outstanding 15 15
Common stock, $0.01 par value,
300,000,000 shares authorized;
201,827,995 and 201,041,320
shares outstanding,
respectively 2,018 2,010
Capital in excess of par value 2,179,258 2,171,514
Accumulated deficit (348,426) (440,137)
-------- --------
Total stockholders' equity 1,832,865 1,733,402
Total liabilities and
stockholders' equity $2,614,083 $2,267,587
========== ==========
Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited; in thousands, except per share data)
Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
---- ---- ---- ----
Operating revenues:
Oil sales $73,349 $49,095 $218,242 $117,093
Natural gas sales 11,265 6,832 30,019 14,677
------ ----- ------ ------
Total operating revenues 84,614 55,927 248,261 131,770
Operating expenses:
Lease operating expenses 11,624 9,961 36,708 24,229
Production taxes 5,444 3,478 16,168 8,153
Depreciation, depletion
and amortization 28,525 17,303 79,172 49,318
General and
administrative 7,259 7,891 18,894 19,755
Settled share-based
awards - - 6,351 -
Accretion expense 131 187 523 762
Write-down of oil and
natural gas properties - - - 95,788
Acquisition expense 205 456 3,027 2,410
--- --- ----- -----
Total operating expenses 53,188 39,276 160,843 200,415
Income (loss) from
operations 31,426 16,651 87,418 (68,645)
------ ------ ------ -------
Other (income) expenses:
Interest expense, net of
capitalized amounts 444 831 1,698 10,502
(Gain) loss on derivative
contracts 14,162 (5,135) (11,636) 11,281
Other income (498) (122) (1,270) (299)
Total other (income)
expense 14,108 (4,426) (11,208) 21,484
------ ------ ------- ------
Income (loss) before
income taxes 17,318 21,077 98,626 (90,129)
Income tax (benefit)
expense 237 (62) 1,026 (62)
--- --- ----- ---
Net income (loss) 17,081 21,139 97,600 (90,067)
Preferred stock dividends (1,824) (1,824) (5,471) (5,471)
Income (loss) available
to common stockholders $15,257 $19,315 $92,129 $(95,538)
======= ======= ======= ========
Income (loss) per common share:
Basic $0.08 $0.14 $0.46 $(0.85)
Diluted $0.08 $0.14 $0.46 $(0.85)
Shares used in computing income (loss) per common share:
Basic 201,827 136,983 201,422 112,925
Diluted 202,337 137,483 201,995 112,925
Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
---- ---- ---- ----
Cash flows from operating activities:
Net income (loss) $17,081 $21,139 $97,600 $(90,067)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion
and amortization 29,132 17,733 80,829 50,560
Write-down of oil and
natural gas properties - - - 95,788
Accretion expense 131 187 523 762
Amortization of non-
cash debt related
items 441 810 1,695 2,371
Deferred income tax
(benefit) expense 237 (62) 1,026 (62)
Net (gain) loss on
derivatives, net of
settlements 12,947 (1,044) (15,608) 27,105
Loss on sale of other
property and equipment - - 62 -
Non-cash expense
related to equity
share-based awards 1,219 778 7,014 1,954
Change in the fair
value of liability
share-based awards 732 3,371 2,423 6,045
Payments to settle
asset retirement
obligations (250) (576) (1,831) (895)
Changes in current assets and
liabilities:
Accounts receivable (4,338) (11,608) (12,148) (16,444)
Other current assets (38) 54 (336) (251)
Current liabilities 1,854 15,702 7,534 19,815
Change in other long-
term liabilities 1 - 121 86
Change in long-term
prepaid (4,650) - (4,650) -
Change in other assets,
net (606) (1,221) (1,376) (1,671)
Payments to settle
vested liability
share-based awards - - (13,173) (10,300)
Net cash provided by
operating activities 53,893 45,263 149,705 84,796
------ ------ ------- ------
Cash flows from investing activities:
Capital expenditures (121,128) (47,418) (267,218) (122,698)
Acquisitions (8,015) (18,033) (714,504) (302,057)
Acquisition deposit - (32,700) 46,138 (32,700)
Proceeds from sales of
mineral interests and
equipment - (708) - 22,923
--- ---- --- ------
Net cash used in
investing activities (129,143) (98,859) (935,584) (434,532)
-------- ------- -------- --------
Cash flows from financing activities:
Borrowings on senior
secured revolving
credit facility - 74,000 - 217,000
Payments on senior
secured revolving
credit facility - (114,000) - (257,000)
Issuance of 6.125%
senior unsecured notes
due 2024 - - 200,000 -
Premium on the issuance
of 6.125% senior
unsecured notes due
2024 - - 8,250 -
Issuance of common
stock - 421,908 - 722,715
Payment of preferred
stock dividends (1,824) (1,824) (5,471) (5,471)
Payment of deferred
financing costs (401) (640) (7,166) (640)
Tax withholdings
related to restricted
stock units (65) (170) (1,118) (2,207)
Net cash provided by
financing activities (2,290) 379,274 194,495 674,397
------ ------- ------- -------
Net change in cash and
cash equivalents (77,540) 325,678 (591,384) 324,661
Balance, beginning of
period 139,149 207 652,993 1,224
Balance, end of period $61,609 $325,885 $61,609 $325,885
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Non-GAAP Financial Measures and Reconciliations
This news release refers to non-GAAP financial measures such as "Discretionary Cash Flow," "Adjusted G&A," "Adjusted Income," "Adjusted EBITDA," and "Adjusted Total Revenue." These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.
-- Callon believes that the non-GAAP measure of discretionary cash flow is
useful as an indicator of an oil and natural 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. Discretionary
cash flow is calculated using net income (loss) adjusted for certain
items including depreciation, depletion and amortization, the impact of
financial derivatives (including the mark-to-market effects, net of cash
settlements and premiums paid or received related to our financial
derivatives), remaining asset retirement obligations related to our
divested offshore properties, restructuring and other non-recurring
costs, deferred income taxes and other non-cash income items.
-- Callon believes that the non-GAAP measure of Adjusted G&A is useful to
investors because it provides readers with a meaningful measure of our
recurring G&A expense and provides for greater comparability
period-over-period. The table above details all adjustments to G&A on a
GAAP basis to arrive at Adjusted G&A.
-- We believe that the non-GAAP measure of Adjusted Income available to
common shareholders ("Adjusted Income") and Adjusted Income per diluted
share are useful to investors because they provide readers with a
meaningful measure of our profitability before recording certain items
whose timing or amount cannot be reasonably determined. These measures
exclude the net of tax effects of certain non-recurring items and
non-cash valuation adjustments, which are detailed in the reconciliation
provided above. Prior to being tax-effected and excluded, the amounts
reflected in the determination of Adjusted Income and Adjusted Income
per diluted share above were computed in accordance with GAAP.
-- We calculate Adjusted Earnings before Interest, Income Taxes,
Depreciation, Depletion and Amortization ("Adjusted EBITDA") as Adjusted
Income plus interest expense, income tax expense (benefit) and
depreciation, depletion and amortization expense. Adjusted EBITDA is not
a measure of financial performance under GAAP. Accordingly, it should
not be considered as a substitute for net income (loss), operating
income (loss), cash flow provided by operating activities or other
income or cash flow data prepared in accordance with GAAP. However, we
believe that Adjusted EBITDA provides additional information with
respect to our performance or ability to meet our future debt service,
capital expenditures and working capital requirements. Because Adjusted
EBITDA excludes some, but not all, items that affect net income (loss)
and may vary among companies, the Adjusted EBITDA we present may not be
comparable to similarly titled measures of other companies.
-- We believe that the non-GAAP measure of Adjusted Total Revenue is useful
to investors because it provides readers with a revenue value more
comparable to other companies who account for derivative contracts and
hedges and include their effects in revenue. We believe Adjusted Total
Revenue is also useful to investors as a measure of the actual cash
inflows generated during the period.
Earnings Call Information
The Company will host a conference call on Tuesday, November 7, 2017, to discuss third quarter 2017 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: Tuesday, November 7, 2017, at 8:00 a.m.
Central Time (9:00 a.m. Eastern Time)
Webcast: Select "IR Calendar" under the
"Investors" section of the website:
www.callon.com.
Presentation Slides: Select "Presentations" under the
"Investors" section of the website:
www.callon.com.
Alternatively, you may join by telephone using the following numbers:
Toll Free: 1-888-317-6003
Canada Toll Free: 1-866-284-3684
International: 1-412-317-6061
Access code: 6326656
An archive of the conference call webcast will also be available at www.callon.com under the "Investors" section of the website.
About Callon Petroleum
Callon Petroleum Company is an independent energy company focused on the acquisition, development, exploration, and operation of oil and natural gas properties in the Permian Basin in West Texas.
This news release is posted on the Company's website at www.callon.com and will be archived there for subsequent review under the "News" link on the top of the homepage.
Cautionary Statement Regarding Forward Looking Statements
This news release contains 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 wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; the Company's 2017 guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; and the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "plans" and words of similar meaning. These 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 include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on our website or the SEC's website at www.sec.gov.
For further information contact:
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
1-800-451-1294
i) See "Non-GAAP
Financial
Measures and
Reconciliations"
included
within this
release for
related
disclosures
and
calculations
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SOURCE Callon Petroleum Company
