Callon Petroleum Company Announces First Quarter 2019 Results
HOUSTON, May 6, 2019 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months ended March 31, 2019.
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.
Highlights
-- Increased production to 40.3 Mboe/d (79% oil), an increase of 52%
year-over-year
-- Generated an operating margin of $32.57 per Boe
-- Recently completed a five-well pad in the southern portion of WildHorse,
developing an entire half section in the Wolfcamp A
-- Initial 2(nd) Bone Spring shale well placed on production in the
Delaware and showing positive early performance
-- Continued strong production from a Middle Spraberry well drilled at
Monarch as part of multi-well, co-development of three flow units
-- Improved completion efficiency, measured in stages per day, by more than
25% compared to the same period in 2018
-- Reduced average drilling and completion costs by 15% sequentially,
resulting in an average cost per lateral foot below $1,000
-- Announced the pending sale of certain non-core assets in the southern
Midland Basin for estimated gross proceeds of $260 million, with
potential contingency payments of up to $60 million based upon average
annual commodity prices over a three-year period
-- Reaffirmed a borrowing base of $1.1 billion, pro forma for the pending
non-core asset sale
"We are ahead of our plan to build out an inventory of drilled, uncompleted wells to extend our usage of a larger pad development model, applying this concept to the Delaware Basin as we continue to build upon our success in the Midland Basin. Capitalizing on the efficiencies of larger development, we delivered a sequential decrease in average drilling and completion cost per lateral foot of 15% in the first quarter. Our drilling plan is quickly progressing to the point where we will decrease to four drilling rigs and start larger Delaware Basin pad completions towards the end of the second quarter." commented Joe Gatto, President and Chief Executive Officer. He continued, "The previously announced sale of our Ranger properties will streamline our operations with a focus on three core operating areas with well-established infrastructure. Since we did not have any planned Ranger activity in 2019, the divestiture will not impact our base 2019 activity levels, but will allow us to optimize our 2020 capital allocation with the removal of Ranger drilling obligations. Upon closing, all cash proceeds will be directed to bolstering our financial position. We remain focused on executing our 2019 plan within our previously announced budget range, with the benefit of incremental cash flow from commodity realizations above our planning case flowing to the bottom line and the benefit our shareholders."
Operations Update
At March 31, 2019, we had 524 gross (395.4 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended March 31, 2019 grew 52% to 40.3 Mboe/d (79% oil) as compared to the same period of 2018.
For the three months ended March 31, 2019, we drilled 21 gross (16.4 net) horizontal wells, and placed a combined 13 gross (11.2 net) horizontal wells on production. Wells placed on production during the quarter were completed in the Lower Spraberry, Middle Spraberry, Wolfcamp A and Wolfcamp B within the Midland Basin and the Lower Wolfcamp A within the Delaware Basin.
Midland Basin
We brought 11 gross (9.2 net) wells on production in the Midland Basin during the first quarter with the majority of activity coming from our Monarch area. Our Middle Spraberry well, the Kendra Amanda PSA 33 MS, an 8,000 foot lateral, which was completed as part of a multi-well pad project, has achieved a 30-day average production rate of approximately 110 Boe per thousand lateral feet (90% oil) and continues to perform well.
Near the end of the quarter, in the WildHorse area in Howard County, we began flowback on a five-well pad that employed half section development in the Wolfcamp A. While not all wells have reached 30 days of production, the combined five-well average for current accumulated production includes an average peak rate of over 1,500 Boe per day (92% oil) or approximately 175 Boe per thousand lateral feet.
The previously disclosed outage at a third party gas processing facility in Martin County has been resolved and we currently do not forecast any impact to second quarter production.
Delaware Basin
At our Spur area in Ward County, we placed on production the Wally World A1 01LA and A2 02LA, both Lower Wolfcamp A wells, which together have achieved cumulative production of over 100,000 Boe (84% oil) during their first 30 days of production. Recently, a two-well pad featuring 2(nd) Bone Spring shale and Lower Wolfcamp A co-development at Spur, was completed and placed on production. Both wells have performed as expected during their limited time on production and we will continue to monitor and compare to third party offsets in the area.
The field optimization project that was initiated during the first quarter of 2019 is progressing and is expected to be completed near the end of the second quarter. We currently expect deferred production related to wells shut in for repairs to average 1,600 Boe per day (79% oil) for the second quarter.
Capital Expenditures
For the three months ended March 31, 2019, we incurred $155.2 million in operational capital expenditures (including other items) on an accrual basis as compared to $141.2 million in the fourth quarter of 2018. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):
Three Months Ended March 31, 2019
Operational Capitalized Capitalized Total Capital
Capital
(a) Interest G&A Expenditures
Cash basis (b) $
164,277 $
18,589 $
10,345 $
193,211
Timing
adjustments (c) (9,109) 1,255 (7,854)
Non-cash items 354 354
Accrual basis $
155,168 $
19,844 $
10,699 $
185,711
(a) Includes seismic, land and other
items.
(b) Cash basis is presented here to help
users of financial information
reconcile amounts from the cash
flow statement to the balance sheet
by accounting for timing related
changes in working capital that
align with 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
March 31, 2019 December 31, 2018 March 31, 2018
Net production
Oil (MBbls) 2,858 3,076 1,851
Natural gas
(MMcf) 4,619 4,225 3,240
Total (Mboe) 3,628 3,780 2,391
Average daily
production
(Boe/d) 40,311 41,087 26,567
% oil (Boe
basis) 79
% 81
% 77
%
Oil and natural
gas revenues
(in thousands)
Oil revenue $
141,098 $
150,398 $
115,286
Natural gas
revenue 11,949 11,497 12,154
Total revenue 153,047 161,895 127,440
Impact of
settled
derivatives (290) (1,594) (8,459)
Adjusted Total
Revenue (i) $
152,757 $
160,301 $
118,981
Average realized
sales price
(excluding
impact of
settled
derivatives)
Oil (per Bbl) $
49.37 $
48.89 $
62.28
Natural gas (per
Mcf) 2.59 2.72 3.75
Total (per BOE) 42.18 42.83 53.30
Average realized
sales price
(including
impact of
settled
derivatives)
Oil (per Bbl) $
48.83 $
48.52 $
57.47
Natural gas (per
Mcf) 2.86 2.62 3.89
Total (per BOE) 42.11 42.41 49.76
Additional per
BOE data
Sales price (a) $
42.18 $
42.83 $
53.30
Lease operating
expense 6.63 6.47 5.45
Production taxes 2.98 2.51 3.54
Operating margin $
32.57 $
33.85 $
44.31
Depletion,
depreciation
and
amortization $
16.47 $
15.74 $
14.81
Adjusted G&A (b)
Cash component
(c) $
2.28 $
2.03 $
2.74
Non-cash
component 0.44 0.50 0.51
(a) Excludes the impact of settled
derivatives.
(b) Excludes certain non-recurring
expenses and non-cash valuation
adjustments. Adjusted G&A is a
non-GAAP financial measure; see
the reconciliation provided
within this press release for a
reconciliation of G&A expense on
a GAAP basis to Adjusted G&A
expense.
(c) Excludes the amortization of
equity-settled, share-based
incentive awards and corporate
depreciation and amortization.
Total Revenue. For the quarter ended March 31, 2019, Callon reported total revenue of $153.0 million and total revenue including settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure((i))) of $152.8 million, including the impact of a $0.3 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company's total operating revenue. Average daily production for the quarter was 40.3 Mboe/d compared to average daily production of 41.1 Mboe/d in the fourth quarter of 2018. Average realized prices, including and excluding the effects of hedging, are detailed above.
Hedging impacts. For the quarter ended March 31, 2019, Callon recognized the following hedging-related items (in thousands, except per unit data):
Three Months Ended March 31, 2019
In Thousands Per Unit
Oil derivatives
Net loss on
settlements $
(1,542) $
(0.54)
Net loss on fair
value
adjustments (66,826)
Total loss on
oil derivatives $
(68,368)
Natural gas
derivatives
Net gain on
settlements $
1,252 $
0.27
Net loss on fair
value
adjustments (144)
Total gain on
natural gas
derivatives $
1,108
Total oil &
natural gas
derivatives
Net loss on
settlements $
(290) $
(0.07)
Net loss on fair
value
adjustments (66,970)
Total loss on
total oil &
natural gas
derivatives $
(67,260)
Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended March 31, 2019 was $6.63 per Boe, compared to LOE of $6.47 per Boe in the fourth quarter of 2018. The increase on a per unit basis was primarily attributed to a 1.9% decrease in daily production.
Production Taxes, including ad valorem taxes. Production taxes were $2.98 per Boe for the three months ended March 31, 2019, representing approximately 7.1% of total revenue before the impact of derivative settlements.
Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended March 31, 2019 was $16.47 per Boe compared to $15.74 per Boe in the fourth quarter of 2018. The increase on a per unit basis was primarily attributable to an increase in our depreciable asset base and assumed future development costs related to undeveloped proved reserves relative to our estimated proved reserves as a result of additions made through our horizontal drilling efforts.
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 $9.9 million, or $2.72 per Boe, for the three months ended March 31, 2019 compared to $9.6 million, or $2.53 per Boe, for the fourth quarter of 2018. The cash component of Adjusted G&A was $8.3 million, or $2.28 per Boe, for the three months ended March 31, 2019 compared to $7.7 million, or $2.03 per Boe, for the fourth quarter of 2018.
For the three months ended March 31, 2019, 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
March 31, 2019
Total G&A expense $
11,753
Change in the fair value of
liability share-based awards
(non-cash) (1,889)
Adjusted G&A - total 9,864
Restricted stock share-based
compensation (non-cash) (1,500)
Corporate depreciation &
amortization (non-cash) (88)
Adjusted G&A - cash component $
8,276
Settled share-based awards. During the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in the $3.0 million recorded on the consolidated statements of operations as settled share-based awards.
Income tax expense. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. We recorded an income tax benefit of $5.1 million for the three months ended March 31, 2019, compared to income tax expense of $5.6 million for the three months ended December 31, 2018. The change in income tax is primarily related to the change in our tax position in 2018, when the Company's tax position transitioned from a net deferred tax asset position to a net deferred tax liability position, thereby unwinding the valuation allowance balance to $0 as of December 31, 2018.
2019 Guidance
The Company is maintaining the current full year guidance until the announced sale of non-core assets closes, which is expected to occur during the second quarter. Upon closing, the Company will update applicable guidance categories, but does not expect any changes to the operational capital guidance for the year.
First Quarter
Full Year
2019 Actual
2019 Guidance
Total
production
(Mboe/
d) 40.3
39.5 - 41.5
% oil 79% 77% - 78%
Income
statement
expenses
(per
Boe)
LOE,
including
workovers $6.63
$5.50 - $6.50
Production
taxes,
including
ad
valorem
(%
unhedged
revenue) 7% 7%
Adjusted
G&A:
cash
component
(a) $2.28
$2.00 - $2.50
Adjusted
G&A:
non-
cash
component
(b) $0.44
$0.50 - $1.00
Cash
interest
expense
(c) $0.00 $0.00
Effective
income
tax
rate 21% 22%
Capital
expenditures
($MM,
accrual
basis)
Total
operational
(d) $155
$500 - $525
Capitalized
interest
and
G&A
expenses $31
$100 - $105
Net
operated
horizontal
wells
placed
on
production 11
47 - 49
(a) Excludes stock-based compensation
and corporate depreciation and
amortization. Adjusted G&A is a
non-GAAP financial measure; 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 certain non-recurring
expenses and non-cash valuation
adjustments. Adjusted G&A is a
non-GAAP financial measure; see
the reconciliation provided within
this press release for a
reconciliation of G&A expense on a
GAAP basis to Adjusted G&A
expense.
(c) All interest expense anticipated to
be capitalized.
(d) Includes facilities, equipment,
seismic, land and other items.
Excludes capitalized expenses.
Hedge Portfolio Summary
The following tables summarize our open derivative positions as of March 31, 2019 for the periods indicated:
For the Remainder For the Full Year
Oil contracts
(WTI) of 2019 of 2020
---
Puts
Total volume
(Bbls) 687,500
Weighted average
price per Bbl $
65.00
$
Put spreads
Total volume
(Bbls) 687,500
Weighted average
price per Bbl
Floor (long put) $
65.00
$
Floor (short
put) $
42.50
$
Collar contracts
combined with
short puts
(three-way
collars)
Total volume
(Bbls) 3,484,000 915,000
Weighted average
price per Bbl
Ceiling (short
call) $
67.56 $
65.02
Floor (long put) $
56.58 $
55.00
Floor (short
put) $
43.62 $
45.00
Collar contracts
(two-way
collars)
Total volume
(Bbls) 732,000
Weighted average
price per Bbl
Ceiling (short
call)
$ $
64.63
Floor (long put)
$ $
55.00
Oil contracts
(Midland basis
differential)
---
Swap contracts
Total volume
(Bbls) 5,102,000 4,576,000
Weighted average
price per Bbl $
(3.95) $
(1.29)
Natural gas
contracts
(Henry Hub)
---
Collar contracts
(two-way
collars)
Total volume
(MMBtu) 2,697,500
Weighted average
price per MMBtu
Ceiling (short
call) $
3.68
$
Floor (long put) $
3.09
$
Swap contracts
Total volume
(MMBtu) 1,852,000
Weighted average
price per MMBtu $
2.88
$
Natural gas
contracts (Waha
basis
differential)
---
Swap contracts
Total volume
(MMBtu) 5,961,000 4,758,000
Weighted average
price per MMBtu $
(1.19) $
(1.12)
Income (Loss) Available to Common Shareholders. The Company reported net loss available to common shareholders of $21.4 million for the three months ended March 31, 2019 and Adjusted Income available to common shareholders of $35.4 million, or $0.16 per fully diluted share. Adjusted Income per fully diluted common share, a non-GAAP financial measure((i)), adjusts our income available to common stockholders to reflect our theoretical tax provision for prior period quarters as if the valuation allowance did not exist. The following tables reconcile to the related GAAP measure the Company's income available to common stockholders to Adjusted Income and the Company's net income to Adjusted EBITDA((i)), a non-GAAP financial measure, (in thousands):
Three Months Ended
March 31, 2019 December 31, 2018 March 31, 2018
Income (loss)
available to common
stockholders $
(21,367) $
154,370 $
53,937
(Gain) loss on
derivatives, net of
settlements 66,970 (105,512) (3,978)
Change in the fair
value of share-
based awards 1,881 (1,053) 1,012
Settled share-based
awards 3,024
Tax effect on
adjustments above (15,094) 22,379 622
Change in valuation
allowance (30,281) (11,753)
Adjusted Income (i) $
35,414 $
39,903 $
39,840
Adjusted Income per
fully diluted
common share (i) $
0.16 $
0.17 $
0.20
Three Months Ended
March 31, 2019 December 31, 2018 March 31, 2018
Net income (loss) $
(19,543) $
156,194 $
55,761
(Gain) loss on
derivatives, net of
settlements 66,970 (105,512) (3,978)
Non-cash stock-
based compensation
expense 3,402 770 2,143
Settled share-based
awards 3,024
Acquisition expense 157 1,333 548
Income tax (benefit)
expense (5,149) 5,647 495
Interest expense 738 735 460
Depreciation,
depletion and
amortization 60,672 60,301 36,066
Accretion expense 241 248 218
Adjusted EBITDA (i) $
110,512 $
119,716 $
91,713
Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure((i)), for the three months ended March 31, 2019 was $110.4 million and is reconciled to operating cash flow in the following table (in thousands):
Three Months Ended
March 31, 2019 December 31, 2018 March 31, 2018
Cash flows from
operating
activities:
Net income (loss) $
(19,543) $
156,194 $
55,761
Adjustments to
reconcile net
income to cash
provided by
operating
activities:
Depreciation,
depletion and
amortization 60,672 60,301 36,066
Accretion expense 241 248 218
Amortization of
non-cash debt
related items 738 734 453
Deferred income
tax (benefit)
expense (5,149) 5,647 495
(Gain) loss on
derivatives, net
of settlements 66,970 (105,512) (3,978)
(Gain) loss on
sale of other
property and
equipment 28 (64)
Non-cash expense
related to equity
share-based
awards 4,545 1,823 1,131
Change in the fair
value of
liability share-
based awards 1,881 (1,053) 1,012
Discretionary cash
flow (i) $
110,383 $
118,318 $
91,158
Changes in working
capital (33,864) 33,710 4,512
Payments to settle
asset retirement
obligations (664) (389) (366)
Payments to settle
vested liability
share-based
awards (1,296) (3,089)
Net cash provided
by operating
activities $
74,559 $
151,639 $
92,215
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share data)
March 31, 2019 December 31, 2018
ASSETS Unaudited
Current assets:
Cash and cash equivalents $
10,482 $
16,051
Accounts receivable 137,110 131,720
Fair value of derivatives 11,372 65,114
Other current assets 12,034 9,740
Total current assets 170,998 222,625
Oil and natural gas properties, full
cost accounting method:
Evaluated properties 4,760,071 4,585,020
Less accumulated depreciation,
depletion, amortization and impairment (2,333,589) (2,270,675)
Evaluated oil and natural gas
properties, net 2,426,482 2,314,345
Unevaluated properties 1,432,118 1,404,513
Total oil and natural gas properties,
net 3,858,600 3,718,858
Operating lease right-of-use assets 40,977
Other property and equipment, net 22,413 21,901
Restricted investments 3,450 3,424
Deferred financing costs 5,742 6,087
Fair value of derivatives 385
Other assets, net 6,269 6,278
Total assets $
4,108,834 $
3,979,173
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $
230,990 $
261,184
Operating lease liabilities 29,134
Accrued interest 25,920 24,665
Cash-settleable restricted stock unit
awards 1,060 1,390
Asset retirement obligations 3,771 3,887
Fair value of derivatives 24,550 10,480
Other current liabilities 8,512 13,310
Total current liabilities 323,937 314,916
Senior secured revolving credit facility 330,000 200,000
6.125% senior unsecured notes due 2024 595,971 595,788
6.375% senior unsecured notes due 2026 393,896 393,685
Operating lease liabilities 11,751
Asset retirement obligations 10,189 10,405
Cash-settleable restricted stock unit
awards 2,252 2,067
Deferred tax liability 4,415 9,564
Fair value of derivatives 6,983 7,440
Other long-term liabilities 995 100
Total liabilities 1,680,389 1,533,965
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;
227,884,091 and 227,582,575 shares
outstanding, respectively 2,279 2,276
Capital in excess of par value 2,481,879 2,477,278
Accumulated deficit (55,728) (34,361)
Total stockholders' equity 2,428,445 2,445,208
Total liabilities and stockholders'
equity $
4,108,834 $
3,979,173
Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited; in thousands, except per share data)
Three Months Ended March 31,
2019 2018
---
Operating revenues:
Oil sales $
141,098 $
115,286
Natural gas sales 11,949 12,154
Total operating revenues 153,047 127,440
Operating expenses:
Lease operating expenses 24,067 13,039
Production taxes 10,813 8,463
Depreciation, depletion
and amortization 59,767 35,417
General and
administrative 11,753 8,769
Settled share-based
awards 3,024
Accretion expense 241 218
Acquisition expense 157 548
Total operating expenses 109,822 66,454
Income from operations 43,225 60,986
Other (income) expenses:
Interest expense, net of
capitalized amounts 738 460
Loss on derivative
contracts 67,260 4,481
Other income (81) (211)
Total other (income)
expense 67,917 4,730
Income (loss) before
income taxes (24,692) 56,256
Income tax (benefit)
expense (5,149) 495
Net income (loss) (19,543) 55,761
Preferred stock dividends (1,824) (1,824)
Income (loss) available
to common stockholders $
(21,367) $
53,937
Income per common share:
Basic $
(0.09) $
0.27
Diluted $
(0.09) $
0.27
Weighted average common shares
outstanding:
Basic 227,784 201,921
Diluted 227,784 202,588
Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
Three Months Ended March 31,
2019 2018
---
Cash flows from operating activities:
Net income (loss) $
(19,543) $
55,761
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion
and amortization 60,672 36,066
Accretion expense 241 218
Amortization of non-
cash debt related
items 738 453
Deferred income tax
(benefit) expense (5,149) 495
(Gain) loss on
derivatives, net of
settlements 66,970 (3,978)
Loss on sale of other
property and equipment 28
Non-cash expense
related to equity
share-based awards 4,545 1,131
Change in the fair
value of liability
share-based awards 1,881 1,012
Payments to settle
asset retirement
obligations (664) (366)
Payments for cash-
settled restricted
stock unit awards (1,296) (3,089)
Changes in current assets and
liabilities:
Accounts receivable (5,390) (8,067)
Other current assets (2,294) 61
Current liabilities (26,003) 12,938
Other (177) (420)
Net cash provided by
operating activities 74,559 92,215
Cash flows from investing activities:
Capital expenditures (193,211) (111,330)
Acquisitions (27,947) (38,923)
Acquisition deposit - 900
Proceeds from sale of
assets 13,879
Net cash used in
investing activities (207,279) (149,353)
Cash flows from financing activities:
Borrowings on senior
secured revolving
credit facility 220,000 80,000
Payments on senior
secured revolving
credit facility (90,000) (30,000)
Payment of preferred
stock dividends (1,824) (1,824)
Tax withholdings
related to restricted
stock units (1,025) (560)
Net cash provided by
financing activities 127,151 47,616
Net change in cash and
cash equivalents (5,569) (9,522)
Balance, beginning of
period 16,051 27,995
Balance, end of period 10,482 18,473
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
a comparable metric against other companies in the industry and is a
widely accepted financial indicator of an oil and natural gas company's
ability to generate cash for the use of internally funding their capital
development program and to service or incur debt. Discretionary cash
flow is defined by Callon as net cash provided by operating activities
before changes in working capital and payments to settle asset
retirement obligations and vested liability share-based awards. Callon
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 the cash flow effect may not be
reflected the period in which the operating activities occurred.
Discretionary cash flow is not a measure of a company's financial
performance under GAAP and should not be considered as an alternative to
net cash provided by operating activities (as defined under GAAP), or as
a measure of liquidity, or as an alternative to net income.
-- Adjusted general and administrative expense ("Adjusted G&A") is a
supplemental non-GAAP financial measure that excludes certain
non-recurring expenses and non-cash valuation adjustments related to
incentive compensation plans, as well as non-cash corporate depreciation
and amortization expense. 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 here within details all
adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.
-- Callon believes 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 here within.
-- Callon calculates 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, the
Company believes 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 presented may
not be comparable to similarly titled measures of other companies.
-- Callon believes 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 engage in price risk management
activities through the use of commodity derivative instruments and
reflects the results of derivative settlements with expected cash flow
impacts within total revenues.
Earnings Call Information
The Company will host a conference call on Tuesday, May 7, 2019, to discuss first quarter 2019 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: Tuesday, May 7, 2019, 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: 3634060
An archive of the conference call webcast will be available at www.callon.com under the "Investors" section of the website.
About Callon Petroleum Company
Callon Petroleum Company is an independent energy company focused on the acquisition and development of unconventional onshore oil and natural gas reserves 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; Callon's 2019 production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; and the implementation of Callon's business plans and strategy, as well as statements including the words "believe," "expect," "plans," "may," "will," "should," "could," and words of similar meaning. These statements reflect Callon's current views with respect to future events and financial performance based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. 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. Any forward-looking statement speaks only as of the date on which such statement is made and Callon undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect Callon's future results and could cause results to differ materially from those expressed in Callon's forward-looking statements include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, cost and availability of equipment and labor, Callon's ability to finance Callon's activities and other risks more fully discussed in Callon's filings with the Securities and Exchange Commission, including Callon's Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on Callon's website or the SEC's website at www.sec.gov.
Contact Information
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
1-281-589-5200
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
