Callon Petroleum Company Announces Second Quarter 2018 Results
NATCHEZ, Miss., Aug. 6, 2018 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and six months ended June 30, 2018.
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 second quarter of 2018 and other recent data points include:
-- Increased production to 29.0 MBOE/D (76% oil), an increase of 30%
year-over-year
-- Reduced lease operating expense by 10% year-over-year to $4.99 per BOE
-- Generated an operating margin of $44.17 per BOE, an increase of 37%
year-over-year
-- Recent Wolfcamp A wells in the Fairway area of WildHorse outperforming
oil type curves by approximately 30%
-- Successful Wolfcamp A wells at Spur, including the initiation of pad
co-development of the Upper and Lower Wolfcamp A, significantly
outperforming initial operated wells
-- Continued outperformance from ten-well downspacing test at Fairway
through more than 200 days of production
-- First "mega-pad" placed on production in July and performing favorably
against offset three-well pads
-- Announced entry into a definitive agreement and completed related
financings to acquire approximately 28,657 net surface acres in the
Delaware Basin, providing near-term value contribution from current
production as well as upside potential, with the transaction projected
to close later in the third quarter
-- Executed a multi-year firm transportation agreement covering 15,000
barrels of oil per day to Gulf Coast destination points and
corresponding long-term sales agreements for equivalent volumes based on
Gulf Coast and international pricing benchmarks
Joe Gatto, President and Chief Executive Officer, commented, "Our second quarter results reflect our continued commitment to maximizing returns while thoughtfully growing our business with the support of leading internal cash margins. Halfway through the year, we have drilled and completed more wells than originally anticipated while still managing our capital spending within our original expectations. The team's continued efforts to reduce operating costs have allowed us to nearly match our operating margins from the first quarter, despite lower realized commodity prices." He continued, "We have been preparing for the integration of our recently announced acquisition into a combined Spur business plan and are looking forward to contributions from both the production base of acquired properties as well as incremental drilling and completion activity on the new footprint later this year, driving an expected combined production rate of over 40,000 BOE/d in the fourth quarter. Additionally, we have been preparing for growing production volumes with recent additions to our hedging program and a new firm transportation agreement that is a meaningful first step to increasing our exposure to pricing points outside of the Permian Basin."
Operations Update
At June 30, 2018, we had 267 gross (200.9 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended June 30, 2018 grew approximately 30% to 29.0 MBOE/D (76% oil) as compared to the same period of 2017. The Company expects production for the month of July to be approximately 31.1 MBOE/D (78% oil).
For the three months ended June 30, 2018, we drilled 18 gross (13.7 net) horizontal wells and placed a combined 15 gross (13.7 net) horizontal wells on production.
Midland Basin
During the second quarter, approximately 60% of the net wells placed on production were located in the Midland Basin, with the majority of these wells within our WildHorse area. Of the wells placed on production at WildHorse, over 90% were placed on production during the month of June. These wells had an average lateral length of roughly 8,400 feet. The only wells placed on production in our Monarch area in Midland County were our Casselman 40 21AH and 14H, a Wolfcamp A and B pair test. These wells reached a peak thirty day average of 173 BOE (81% oil) and 214 BOE (83% oil) per lateral foot respectively. Through the first 100 days of production, both have outperformed the 5,000 foot oil type curve for this area.
In the Fairway area of WildHorse, our recent Barclays B Unit pad and Players three-well pad (06AH, 07AH, and 08AH) have both outperformed their respective oil type curves by 29% and 33% (on average) through the initial 40 days of production. Nearby, the Open A2 #1AH and A3 #3AH wells that comprised our 10-well spacing test continue to outperform offsetting comparable pads with eight-well spacing after more than 200 days of production.
Delaware Basin
The Rendezvous A1 #01LA and A2 #09UA, which were placed on production in April, have collectively produced over 260,000 BOE (~85% oil) in their first 100 days on production, significantly outperforming all previous Callon wells at our Spur area. The wells were completed with approximately 7,500 and 7,800 foot laterals, respectively. During the middle of the quarter, we placed the Moran A1 01LA on production with a completed lateral length of just under 5,800 feet. Through the first 75 days of production, the Moran well has produced approximately 80,000 BOE (~75% oil). In June, the Rag Run A1 #01LA and 134 South #25CH wells were completed with lateral lengths of approximately 9,300 and 4,800 feet, respectively, and placed on production. The A1 #01LA has produced approximately 75,000 BOE (~85% oil) through the first 40 days of production. The 134 South #25CH, our first Wolfcamp C test on our Delaware acreage position, has produced over 23,000 BOE (~80% oil) through 43 days.
Firm Transportation Agreement
Recently, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, Reagan and Upton counties to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a commitment of 15,000 Bbls per day for a multi-year term. Multi-year, firm sales agreements covering all 15,000 barrels have already been agreed upon with established buyers in the Gulf Coast region.
Infrastructure and Operational Efficiency
During the second quarter, significant progress was made in the planned infrastructure build out across our operating areas. All planned work at our Ranger area has been completed. At Spur, our new recycling facilities and recycling frac pits are complete, the majority of water transfer line work has been finished, and we have finished the installation of a new power substation.
Continued focus on operational efficiencies resulted in the company placing more wells on production during the second quarter than originally anticipated. Compared to the first quarter, the company placed nearly double the amount of net lateral feet on production during the second quarter, with over half of that coming in June. We have begun to increase our water recycling efforts and have recycled over a half million barrels of produced water through the first half of 2018. The company expects to continue ramping those volumes during the second half of the year. We also recently renewed the contract on a fifth drilling rig for a term of two years.
Capital Expenditures
For the three months ended June 30, 2018, we incurred $163.5 million in cash operational capital expenditures (including other items) compared to $105.3 million in the first quarter of 2018. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):
Three Months Ended June 30, 2018
Operational Capitalized Capitalized Total Capital
Capital (a) Interest G&A Expenditures
---------- -------- --- ------------
Cash basis (b) $163,462 $19,189 $4,389 $187,040
Timing adjustments (c) 2,500 (7,139) - (4,639)
Non-cash items - - 427 427
---
Accrual (GAAP) basis $165,962 $12,050 $4,816 $182,828
======== ======= ====== ========
(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
June 30, 2018 March 31, 2018 June 30, 2017
------------- -------------- -------------
Net production
Oil (MBbls) 1,995 1,851 1,596
Natural gas
(MMcf) 3,839 3,240 2,550
Total (MBOE) 2,635 2,391 2,021
Average daily
production
(BOE/d) 28,954 26,567 22,209
% oil (BOE
basis) 76% 77% 79%
Oil and natural
gas revenues
(in thousands)
Oil revenue $122,613 $115,286 $72,885
Natural gas
revenue (a) 14,462 12,154 9,398
Total revenue 137,075 127,440 82,283
Impact of cash-
settled
derivatives (7,980) (8,459) (267)
Adjusted Total
Revenue (i) $129,095 $118,981 $82,016
======== ======== =======
Average realized
sales price
(excluding
impact of cash
settled
derivatives)
Oil (Bbl) $61.46 $62.28 $45.67
Natural gas
(Mcf) 3.77 3.75 3.69
Total (BOE) 52.02 53.30 40.71
Average realized
sales price
(including
impact of cash
settled
derivatives)
Oil (Bbl) $57.38 $57.47 $45.47
Natural gas
(Mcf) 3.81 3.89 3.70
Total (BOE) 48.99 49.76 40.58
Additional per
BOE data
Sales price (b) $52.02 $53.30 $40.71
Lease operating
expense (c) 4.99 5.45 5.56
Gathering and
treating
expense (a) - - 0.45
Production taxes 2.86 3.54 2.38
Operating margin $44.17 $44.31 $32.32
====== ====== ======
Depletion,
depreciation
and
amortization $14.70 $14.81 $12.97
Adjusted G&A (d)
Cash component
(e) $2.69 $2.74 $2.67
Non-cash
component 0.64 0.51 0.53
(a) On January 1, 2018, the Company
adopted the revenue recognition
accounting standard. Consequently,
natural gas gathering and treating
expenses for the three and six
months ended June 30, 2018 were
accounted for as a reduction to
revenue.
(b) Excludes the impact of cash-settled
derivatives.
(c) Excludes gathering and treating
expense.
(d) 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.
(e) Excludes the amortization of equity-
settled share-based incentive
awards and corporate depreciation
and amortization.
Total Revenue. For the quarter ended June 30, 2018, Callon reported total revenue of $137.1 million and total revenue including cash-settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure((i))) of $129.1 million, including the impact of an $8.0 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 29.0 MBOE/d compared to average daily production of 26.6 MBOE/d in the first quarter of 2018. Average realized prices, including and excluding the effects of hedging, are detailed above.
Hedging impacts. For the quarter ended June 30, 2018, Callon recognized the following hedging-related items (in thousands, except per unit data):
In Thousands Per Unit
------------ --------
Oil derivatives
Net loss on settlements $(8,131) $(4.08)
Net loss on fair value adjustments (8,311)
Total loss on oil derivatives $(16,442)
========
Natural gas derivatives
Net gain on settlements $151 $0.04
Net loss on fair value adjustments (263)
Total loss on natural gas derivatives $(112)
=====
Total oil & natural gas derivatives
Net loss on settlements $(7,980) $(3.03)
Net loss on fair value adjustments (8,574)
Total loss on total oil & natural gas derivatives $(16,554)
========
Lease Operating Expenses, including workover ("LOE"). LOE per BOE for the three months ended June 30, 2018 was $4.99 per BOE, compared to LOE of $5.45 per BOE in the first quarter of 2018. The decrease in this metric resulted primarily from a decrease in saltwater disposal costs and an increase in production volumes period over period.
Production Taxes, including ad valorem taxes. Production taxes were $2.86 per BOE for the three months ended June 30, 2018, representing approximately 5.5% of total revenue before the impact of derivative settlements.
Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended June 30, 2018 was $14.70 per BOE compared to $14.81 per BOE in the first quarter of 2018. The decrease is attributable to our increased estimated proved reserves relative to our depreciable base and assumed future development costs related to undeveloped proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions.
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 $8.8 million, or $3.33 per BOE, for the three months ended June 30, 2018 compared to $7.8 million, or $3.25 per BOE, for the first quarter of 2018. The cash component of Adjusted G&A was $7.1 million, or $2.69 per BOE, for the three months ended June 30, 2018 compared to $6.5 million, or $2.74 per BOE, for the first quarter of 2018.
For the three months ended June 30, 2018, 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
June 30, 2018
-------------
Total G&A expense $8,289
Plus: Change in the fair value of liability share-based awards (non-cash) 484
---
Adjusted G&A - total 8,773
Less: Restricted stock share-based compensation (non-cash) (1,587)
Less: Corporate depreciation & amortization (non-cash) (109)
Adjusted G&A - cash component $7,077
======
Income tax expense. Callon provides for income taxes at a statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls and shortfalls, and state income taxes. We recorded an income tax expense of $0.5 million for the three months ended June 30, 2018 which relates to deferred state franchise tax. At June 30, 2018 we had a valuation allowance of $38.6 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 $10.6 million (or $0.05 per diluted share) for the quarter as if the valuation allowance did not exist.
2018 Guidance
The Company adopted the Revenue from Contracts with Customers accounting standard on January 1, 2018. Starting with the first quarter of 2018, certain natural gas gathering and treating expenses were accounted for as a reduction to revenue. The Company expects to provide updated guidance upon the closing of the previous announced acquisition of assets in the Delaware Basin for $570 million.
Second Quarter First Half Full Year
2018 Actual 2018 Actual 2018 Guidance
----------- ----------- -------------
Total
production
(MBOE/
d) 29.0 27.8 29.5 - 32.0
%
oil 76% 77% 77%
Income
statement
expenses
(per
BOE)
LOE,
including
workovers $4.99 $5.21 $5.25 - $6.25
Production
taxes,
including
ad
valorem
(%
unhedged
revenue) 5% 6% 6%
Adjusted
G&A:
cash
component
(a) $2.69 $2.71 $1.75 - $2.50
Adjusted
G&A:
non-
cash
component
(b) $0.64 $0.58 $0.50 - $1.00
Interest
expense
(c) $0.00 $0.00 $0.00
Effective
income
tax
rate 22% 22% 22%
Capital
expenditures
($MM,
accrual
basis)
Operational
(d) $166 $283 $500 - $540
Capitalized
expenses $17 $33 $60 - $70
Net
operated
horizontal
wells
placed
on
production 14 23 43 - 46
(a) Excludes stock-based compensation
and corporate depreciation and
amortization.
(b) Excludes certain non-recurring
expenses and non-cash valuation
adjustments.
(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 Remainder For the Full Year For the Full Year
Oil contracts
(WTI) of 2018 of 2019 of 2020
------------- ------- ------- -------
Swap contracts
Total volume
(Bbls) 1,104,000 - -
Weighted average
price per Bbl $52.07 $ - $ -
Collar contracts
(two-way
collars)
Total volume
(Bbls) 184,000 - -
Weighted average
price per Bbl
Ceiling (short
call) $60.50 $ - $ -
Floor (long put) $50.00 $ - $ -
Collar contracts
combined with
short puts
(three-way
collars)
Total volume
(Bbls) 1,748,000 3,469,000 -
Weighted average
price per Bbl
Ceiling (short
call option) $60.86 $63.71 $ -
Floor (long put
option) $48.95 $53.95 $ -
Short put option $39.21 $43.95 $ -
Puts
Total volume
(Bbls) 552,000 1,825,000 -
Weighted average
price per Bbl $65.00 $65.00 $ -
Oil contracts
(Midland basis
differential)
---------------
Swap contracts
Total volume
(Bbls) 2,208,000 4,380,000 3,660,000
Weighted average
price per Bbl $(4.26) $(4.77) $(1.47)
Natural gas
contracts
(Henry Hub)
------------
Swap contracts
Total volume
(MMBtu) 2,760,000 - -
Weighted average
price per MMBtu $2.91 $ - $ -
Collar contracts
(two-way
collars)
Total volume
(MMBtu) 1,104,000 2,372,500 -
Weighted average
price per MMBtu
Ceiling (short
call) $3.19 $2.95 $ -
Floor (long put) $2.75 $2.65 $ -
Natural gas
contracts (Waha
basis
differential)
----------------
Swap contracts
Total volume
(MMBtu) 1,104,000 2,190,000 2,196,000
Weighted average
price per MMBtu $(1.14) $(1.14) $(1.14)
Income Available to Common Shareholders. The Company reported net income available to common shareholders of $48.7 million for the three months ended June 30, 2018 and Adjusted Income available to common shareholders of $44.5 million, or $0.21 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 the quarter 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, a non-GAAP financial measure, (in thousands):
Three Months Ended
June 30, 2018 March 31, 2018 June 30, 2017
------------- -------------- -------------
Income available to
common stockholders $48,650 $53,937 $31,566
Change in valuation
allowance (10,562) (11,753) (11,194)
Net (gain) loss on
derivatives, net of
settlements 6,772 (3,143) (6,995)
Change in the fair
value of share-
based awards (366) 799 (315)
Settled share-based
awards - - 4,128
--- --- -----
Adjusted Income $44,494 $39,840 $17,190
======= ======= =======
Adjusted Income per
fully diluted
common share $0.21 $0.20 $0.09
===== ===== =====
Three Months Ended
June 30, 2018 March 31, 2018 June 30, 2017
------------- -------------- -------------
Net income $50,474 $55,761 $33,390
Net (gain) loss on
derivatives, net of
settlements 8,572 (3,978) (10,761)
Non-cash stock-
based compensation
expense 1,164 2,143 499
Settled share-based
awards - - 6,351
Acquisition expense 1,767 548 2,373
Income tax expense 481 495 322
Interest expense 594 460 589
Depreciation,
depletion and
amortization 39,387 36,066 26,765
Accretion expense 206 218 208
--- ---
Adjusted EBITDA $102,645 $91,713 $59,736
======== ======= =======
Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure((i)), for the three months ended June 30, 2018 was $100.9 million and is reconciled to operating cash flow in the following table (in thousands):
Three Months Ended
June 30, 2018 March 31, 2018 June 30, 2017
------------- -------------- -------------
Cash flows from
operating
activities:
Net income $50,474 $55,761 $33,390
Adjustments to
reconcile net
income to cash
provided by
operating
activities:
Depreciation,
depletion and
amortization 39,387 36,066 26,765
Accretion expense 206 218 208
Amortization of
non-cash debt
related items 588 453 589
Deferred income
tax expense 481 495 323
Net (gain) loss on
derivatives, net
of settlements 8,572 (3,978) (10,761)
Loss on sale of
other property
and equipment 22 - 62
Non-cash expense
related to equity
share-based
awards 1,627 1,131 4,865
Change in the fair
value of
liability share-
based awards (463) 1,012 1,982
-----
Discretionary cash
flow $100,894 $91,158 $57,423
======== ======= =======
Changes in working
capital 8,978 4,512 (8,968)
Payments to settle
asset retirement
obligations (207) (366) (816)
Payments to settle
vested liability
share-based
awards (1,901) (3,089) (4,511)
Net cash provided
by operating
activities $107,764 $92,215 $43,128
======== ======= =======
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)
June 30, 2018 December 31, 2017
------------- -----------------
ASSETS Unaudited
Current assets:
Cash and cash equivalents $509,146 $27,995
Accounts receivable 111,964 114,320
Fair value of derivatives 11,569 406
Other current assets 7,689 2,139
----- -----
Total current assets 640,368 144,860
------- -------
Oil and natural gas properties, full cost
accounting method:
Evaluated properties 3,814,242 3,429,570
Less accumulated depreciation,
depletion, amortization and
impairment (2,158,225) (2,084,095)
---------- ----------
Net evaluated oil and natural
gas properties 1,656,017 1,345,475
Unevaluated properties 1,144,138 1,168,016
--------- ---------
Total oil and natural gas
properties 2,800,155 2,513,491
--------- ---------
Other property and equipment,
net 21,514 20,361
Restricted investments 3,393 3,372
Deferred tax asset 26 52
Deferred financing costs 5,749 4,863
Fair value of derivatives 2,299 -
Acquisition deposit 28,500 900
Other assets, net 5,322 5,397
----- -----
Total assets $3,507,326 $2,693,296
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued
liabilities $193,981 $162,878
Accrued interest 11,351 9,235
Cash-settleable restricted
stock unit awards 1,781 4,621
Asset retirement obligations 2,284 1,295
Fair value of derivatives 35,948 27,744
------ ------
Total current liabilities 245,345 205,773
------- -------
Senior secured revolving credit
facility - 25,000
6.125% senior unsecured notes
due 2024, net of unamortized
deferred financing costs 595,552 595,196
6.375% senior unsecured notes
due 2026, net of unamortized
deferred financing costs 392,907 -
Asset retirement obligations 7,782 4,725
Cash-settleable restricted
stock unit awards 1,900 3,490
Deferred tax liability 2,431 1,457
Fair value of derivatives 11,136 1,284
Other long-term liabilities 665 405
--- ---
Total liabilities 1,257,718 837,330
--------- -------
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;
227,507,031 and 201,836,172
shares outstanding,
respectively 2,275 2,018
Capital in excess of par value 2,472,155 2,181,359
Accumulated deficit (224,837) (327,426)
-------- --------
Total stockholders' equity 2,249,608 1,855,966
--------- ---------
Total liabilities and
stockholders' equity $3,507,326 $2,693,296
========== ==========
Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited; in thousands, except per share data)
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2018 2017 2018 2017
---- ---- ---- ----
Operating revenues:
Oil sales $122,613 $72,885 $237,898 $144,893
Natural gas sales 14,462 9,398 26,617 18,754
------ ----- ------ ------
Total operating revenues 137,075 82,283 264,515 163,647
Operating expenses:
Lease operating expenses 13,141 12,145 26,179 25,084
Production taxes 7,539 4,820 16,002 10,723
Depreciation, depletion
and amortization 38,733 26,213 74,151 50,646
General and
administrative 8,289 6,430 17,057 11,636
Settled share-based
awards - 6,351 - 6,351
Accretion expense 206 208 424 392
Acquisition expense 1,767 2,373 2,315 2,822
Total operating expenses 69,675 58,540 136,128 107,654
------ ------ ------- -------
Income from operations 67,400 23,743 128,387 55,993
------ ------ ------- ------
Other (income) expenses:
Interest expense, net of
capitalized amounts 594 589 1,053 1,254
(Gain) loss on derivative
contracts 16,554 (10,494) 21,036 (25,797)
Other income (703) (64) (914) (772)
---- --- ---- ----
Total other (income)
expense 16,445 (9,969) 21,175 (25,315)
------ ------ ------ -------
Income before income
taxes 50,955 33,712 107,212 81,308
Income tax expense 481 322 976 789
--- --- --- ---
Net income 50,474 33,390 106,236 80,519
Preferred stock dividends (1,824) (1,824) (3,647) (3,647)
------ ------ ------ ------
Income available to
common stockholders $48,650 $31,566 $102,589 $76,872
======= ======= ======== =======
Income per common share:
Basic $0.23 $0.16 $0.50 $0.38
Diluted $0.23 $0.16 $0.50 $0.38
Shares used in computing income per common
share:
Basic 210,698 201,386 206,309 201,220
Diluted 211,465 201,905 207,027 201,823
Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
Three Months Ended June 30, Six Months Ended June 30,
2018 2017 2018 2017
---- ---- ---- ----
Cash flows from operating activities:
Net income $50,474 $33,390 $106,236 $80,519
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion
and amortization 39,387 26,765 75,453 51,697
Accretion expense 206 208 424 392
Amortization of non-
cash debt related
items 588 589 1,041 1,254
Deferred income tax
expense 481 323 976 789
Net (gain) loss on
derivatives, net of
settlements 8,572 (10,761) 4,594 (28,555)
Loss on sale of other
property and equipment 22 62 22 62
Non-cash expense
related to equity
share-based awards 1,627 4,865 2,758 5,795
Change in the fair
value of liability
share-based awards (463) 1,982 549 1,691
Payments to settle
asset retirement
obligations (207) (816) (573) (1,581)
Changes in current assets and
liabilities:
Accounts receivable 10,447 (3,744) 2,380 (7,810)
Other current assets (5,611) (874) (5,550) (298)
Current liabilities 4,123 (4,223) 17,061 5,680
Other long-term
liabilities 200 120 287 120
Other assets, net (181) (247) (689) (770)
Payments to settle
vested liability
share-based awards (1,901) (4,511) (4,990) (13,173)
Net cash provided by
operating activities 107,764 43,128 199,979 95,812
------- ------ ------- ------
Cash flows from investing activities:
Capital expenditures (187,040) (79,936) (298,370) (146,090)
Acquisitions (6,469) (58,004) (45,392) (706,489)
Acquisition deposit (28,500) - (27,600) 46,138
Proceeds from sale of
assets 3,077 - 3,077 -
Net cash used in
investing activities (218,932) (137,940) (368,285) (806,441)
-------- -------- -------- --------
Cash flows from financing activities:
Borrowings on senior
secured revolving
credit facility 85,000 - 165,000 -
Payments on senior
secured revolving
credit facility (160,000) - (190,000) -
Issuance of 6.125%
senior unsecured notes
due 2024 - 200,000 - 200,000
Premium on the issuance
of 6.125% senior
unsecured notes due
2024 - 8,250 - 8,250
Issuance of 6.375%
senior unsecured notes
due 2026 400,000 - 400,000 -
Issuance of common
stock 288,357 - 288,357 -
Payment of preferred
stock dividends (1,824) (1,823) (3,647) (3,647)
Payment of deferred
financing costs (8,664) (6,765) (8,664) (6,765)
Tax withholdings
related to restricted
stock units (1,028) (974) (1,589) (1,053)
Net cash provided by
financing activities 601,841 198,688 649,457 196,785
------- ------- ------- -------
Net change in cash and
cash equivalents 490,673 103,876 481,151 (513,844)
Balance, beginning of
period 18,473 35,273 27,995 652,993
------ ------ -------
Balance, end of period $509,146 $139,149 $509,146 $139,149
======== ======== ======== ========
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), accretion expense, 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, August 7, 2018, to discuss second quarter 2018 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: Tuesday, August 7, 2018, 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: 8210968
An archive of the conference call webcast will 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 2018 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.
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
