Callon Petroleum Company Announces Fourth Quarter 2017 Results
NATCHEZ, Miss., Feb. 27, 2018 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months and full-year ended December 31, 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 fourth quarter of 2017, and other recent data points, include:
-- Full-year 2017 production of 22.9 MBOE/d (78% oil), an increase of 50%
over 2016 volumes
-- Fourth quarter 2017 production of 26.5 MBOE/d (79% oil), a sequential
quarterly increase of 18%
-- Year-end proved reserves of 137.0 MMBOE (78% oil), a year-over-year
increase of 50%
-- Organic reserve replacement((i)) of 566% of 2017 production at a
"Drill-Bit" finding and development cost concept((i)) of $8.21 per BOE
on a two-stream basis
-- Reduced lease operating expense to $4.84 per BOE in the fourth quarter
of 2017, a sequential quarterly decrease of 5%, contributing to a total
reduction of 27% since the first quarter of 2017
-- Generated a fourth quarter operating margin of $40.51 per BOE
-- Currently operating five horizontal rigs and two dedicated completion
crews
Joe Gatto, President and Chief Executive Officer commented, "Our full year results for 2017 highlight solid execution by our team, resulting in annual production growth of more than 50% and a greater than 25% reduction in lease operating expense over the course of the year. Our operating margins improved 30% over 2016 and our oil content remained just below 80%, contributing to strong internal cash flow generation. Importantly, these top tier cash margins, coupled with drill-bit finding and development cost below $10 per BOE, are a fundamental driver of corporate level returns that continue to improve in parallel with our growth in producing assets. We have recently increased our operating activity to five drilling rigs and plan to remain at this pace for the balance of 2018 as we incorporate larger pad development concepts into our program and drive steady improvement in our net cash flow profile over the course of the year."
Operations Update
At December 31, 2017, we had 232 gross (171.8 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended December 31, 2017 grew approximately 44% to 26.5 thousand barrels of oil equivalent per day (approximately 79% oil) as compared to the same period of 2016. Full year production for 2017 averaged 22,940 barrels of oil equivalent per day (approximately 78% oil) reflecting growth of 50% over 2016 volumes.
Midland Basin
During the fourth quarter, over 50% of the wells placed on production were from our WildHorse area with an average completed lateral length of approximately 7,300 feet. This area continues to be a key area of production growth for the company and is projected to comprise in excess of 30% of our total gross drilling activity in 2018. Completed lateral lengths are projected to average over 8,000 feet and the majority of activity will continue to focus predominantly on the development of the Wolfcamp A.
In our Monarch area, we placed six wells on production during the quarter. Activity in this area continues to focus on the Lower Spraberry which has consistently generated some of the highest returns in our portfolio. The three-well Kendra pad, with average completed lateral lengths of approximately 10,350, has produced over 236,000 BOE (87% oil) over the first 90 days online. Additionally, we commenced production of our first multi-well pad that utilized recycled flowback water volumes and plan to increase recycling activity in Monarch with upcoming wells. Our 2018 activity plan for Monarch will feature two separate "mega-pad" concepts incorporating simultaneous development of two contiguous three-well pads. Each pad will be drilled concurrently by dedicated rigs and all six wells placed on production at the same time. We expect these larger pads to be placed on production during the second half of the year.
In Reagan County at the Ranger area, our first Wolfcamp C well, together with two Lower Wolfcamp B wells, was completed during the fourth quarter and began flowback in January. The Wolfcamp C well continues to produce under natural flowing pressure with recent production rates in excess of 1,000 BOE/d (85% - 90% oil) and is still in the process of establishing a peak rate. We anticipate drilling four (gross) additional Wolfcamp C wells in Ranger during the course of 2018 with an average working interest of approximately 55%.
Delaware Basin
We recently completed drilling of our first two-well pad in the area and also added a second rig to our Spur development program in February. As part of this increased activity, we plan to enhance our existing saltwater disposal capacity of over 100,000 barrels per day with the connection to a pipeline system operated by Goodnight Midstream that will move water disposal volumes outside of our operating area. In addition, we are in the final stages of establishing a recycling program in this area and targeting usage of up to 50% recycled volumes for completion operations by year end 2018. During the fourth quarter, the Saratoga 7LA well came online and has produced at an average daily rate of approximately 1,015 BOE/d (83% oil) during its first 56 days of production.
Capital Expenditures
For the three months ended December 31, 2017, we incurred $115.8 million in accrued operational capital expenditures (excluding other items) compared to $113.4 million in the third quarter of 2017. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):
Three Months Ended December 31, 2017
Operational Capitalized Capitalized Total Capital
Capital Other (a) Interest G&A Expenditures
------- -------- -------- --- ------------
Cash basis (b) $123,664 $5,006 $18,848 $5,103 $152,621
Timing
adjustments (c) (7,910) - (9,140) - (17,050)
Non-cash items - - - 1,173 1,173
Accrual (GAAP)
basis $115,754 $5,006 $9,708 $6,276 $136,744
======== ====== ====== ====== ========
(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.
We also divested certain infrastructure during the fourth quarter for proceeds of just over $20 million. We anticipate Callon will have additional opportunities to selectively monetize other infrastructure and facilities investments as we leverage strategic partnerships and increasingly transition to the use of recycled water volumes in our completion operations.
Operating and Financial Results
The following table presents summary information for the periods indicated:
Three Months Ended
December 31, 2017 September 30, 2017 December 31, 2016
----------------- ------------------ -----------------
Net production
Oil (MBbls) 1,936 1,591 1,287
Natural gas
(MMcf) 3,018 2,900 2,412
Total (MBOE) 2,439 2,074 1,689
Average daily
production
(BOE/d) 26,511 22,543 18,359
% oil (BOE
basis) 79% 77% 76%
Oil and natural
gas revenues
(in thousands)
Oil revenue $104,132 $73,349 $60,559
Natural gas
revenue 14,081 11,265 8,522
------ ------
Total 118,213 84,614 69,081
Impact of cash-
settled
derivatives (4,501) (1,214) 2,079
Adjusted Total
Revenue (i) $113,712 $83,400 $71,160
======== ======= =======
Average realized
sales price
(excluding
impact of cash
settled
derivatives)
Oil (Bbl) $53.79 $46.10 $47.05
Natural gas
(Mcf) 4.67 3.88 3.53
Total (BOE) 48.47 40.80 40.90
Average realized
sales price
(including
impact of cash
settled
derivatives)
Oil (Bbl) $51.28 $45.24 $48.87
Natural gas
(Mcf) 4.78 3.94 3.43
Total (BOE) 46.62 40.21 42.13
Additional per
BOE data
Sales price (a) $48.47 $40.80 $40.90
Lease operating
expense (b) 4.84 5.08 7.96
Gathering and
treating
expense 0.57 0.52 0.40
Production taxes 2.55 2.62 2.20
---- ---- ----
Operating margin $40.51 $32.58 $30.34
====== ====== ======
Depletion,
depreciation
and
amortization $14.98 $13.75 $13.06
Adjusted G&A (c)
Cash component
(d) $2.46 $2.50 $2.84
Non-cash
component 0.54 0.65 0.54
(a) Excludes the impact of cash
settled derivatives.
(b) Excludes gathering and treating
expense.
(c) 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.
(d) Excludes the amortization of
equity-settled share-based
incentive awards and corporate
depreciation and amortization.
Total Revenue. For the quarter ended December 31, 2017, Callon reported total revenue of $118.2 million and total revenue including cash-settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure((i))) of $113.7 million, including the impact of a $4.5 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 26.5 MBOE/d compared to average daily production of 22.5 MBOE/d in the third quarter of 2017. Average realized prices, including and excluding the effects of hedging, are detailed below.
Hedging impacts. For the quarter ended December 31, 2017, Callon recognized the following hedging-related items (in thousands, except per unit data):
Three Months Ended December 31, 2017
In Thousands Per Unit
------------ --------
Oil derivatives
Net loss on settlements $(4,854) $(2.51)
Net loss on fair value adjustments (26,010)
Total loss on oil derivatives $(30,864)
--------
Natural gas derivatives
Net gain on settlements $353 $0.11
Net loss on fair value adjustments (26)
Total gain on natural gas derivatives $327
----
Total oil & natural gas derivatives
Net loss on settlements $(4,501) $(1.85)
Net loss on fair value adjustments (26,036)
Total loss on total oil & natural gas derivatives $(30,537)
========
Lease Operating Expenses, including workover and gathering expense ("LOE"). LOE per BOE for the three months ended December 31, 2017 was $5.41 per BOE, compared to LOE of $5.60 per BOE in the third quarter of 2017. The decrease in this metric resulted primarily from an increase in production period over period.
Production Taxes, including ad valorem taxes. Production taxes were $2.55 per BOE for the three months ended December 31, 2017, representing approximately 5.3% of total revenue before the impact of derivative settlements.
Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended December 31, 2017 was $14.98 per BOE compared to $13.75 per BOE in the third 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 $7.3 million, or $3.00 per BOE, for the three months ended December 31, 2017 compared to $6.5 million, or $3.15 per BOE, for the third quarter of 2017. The cash component of Adjusted G&A was $6.0 million, or $2.46 per BOE, for the three months ended December 31, 2017 compared to $5.2 million, or $2.50 per BOE, for the third quarter of 2017.
For the three months ended December 31, 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
December 31, 2017
-----------------
Total G&A expense $8,173
Less: Change in the fair value of
liability share-based awards
(non-cash) (844)
----
Adjusted G&A - total 7,329
Less: Restricted stock share-based
compensation (non-cash) (1,202)
Less: Corporate depreciation &
amortization (non-cash) (125)
Adjusted G&A - cash component $6,002
======
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 December 31, 2017 which relates to deferred State of Texas gross margin tax. At December 31, 2017 we had a valuation allowance of $60.9 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 $8.3 million (or $0.04 per diluted share) for the quarter as if the valuation allowance did not exist.
Proved Reserves
The Company recently completed the reserve audit for the year ended December 31, 2017 with its independent reserve auditor, DeGolyer and MacNaughton. As of December 31, 2017, Callon's estimated total proved reserves were 137.0 MMBOE, a 50% increase over the previous year-end. The proved reserves estimate is comprised of 78% oil of which our total proved developed estimated volumes are comprised of 75% oil.
The following table presents the progression of our estimated net proved oil and natural gas reserves from December 31, 2016 to 2017, and in each case, prepared in accordance with the rules and regulations of the SEC.
Proved developed and undeveloped reserves Oil (MBbls) Natural Gas (MMcf) Total (MBOE)
---------- ----------------- -----------
As of December 31, 2016 71,145 122,611 91,580
Revisions to previous estimates (5,171) 6,336 (4,115)
Extensions and discoveries 39,267 48,648 47,375
Purchases, net of sales, of reserves in place 8,388 12,711 10,507
Production (6,557) (10,896) (8,373)
As of December 31, 2017 107,072 179,410 136,974
======= ======= =======
Callon added a total of 47.4 MMBOE in 2017 from horizontal development of our properties, replacing 566% of 2017 production as calculated by the sum of reserve extensions and discoveries, divided by annual production ("Organic reserve replacement"). The Company's finding and development costs from extensions and discoveries ("Drill-Bit F&D costs") were $8.21 per BOE calculated as accrual costs incurred for exploration and development divided by the reserves (in barrels of oil equivalent) added from extensions and discoveries. See "Non-GAAP Financial Measures and Reconciliations" included within this release for related disclosures and calculations.
Guidance Update
As a result of the Tax Cuts and Jobs Act, signed into law in December 2017 and effective January 1, 2018, the new federal statutory income tax rate was reduced to 21% from 35%. In addition, 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 will be accounted for as a reduction to revenue.
2017 Actual 2018 Forecast
----------- -------------
Total production (MBOE/d) 22.9 29.5 - 32.0
% oil 78% 77%
Income statement expenses (per BOE)
LOE, including workovers $5.46 $5.25 - $6.25
Production taxes, including ad valorem (% unhedged revenue) 6% 6%
Adjusted G&A: cash component (a) $2.51 $1.75 - $2.50
Adjusted G&A: non-cash component (b) $0.57 $0.50 - $1.00
Interest expense (c) $0.00 $0.00
Statutory income tax rate 36% 22%
Capital expenditures ($MM, accrual basis)
Operational (net of monetizations) (d) $389 $500 - $540
Capitalized expenses $48 $60 - $70
Net operated horizontal wells placed on production 37 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 Full Year For the Full Year
of of
Oil contracts (WTI) 2018 2019
------------------- ---- ----
Swap contracts
Total volume (MBbls) 2,009 -
Weighted average price per Bbl $51.78 $ -
Collar contracts (two-way collars)
Total volume (MBbls) 365 -
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 (MBbls) 3,468 1,825
Weighted average price per Bbl
Ceiling (short call option) $60.86 $62.40
Floor (long put option) $48.95 $53.00
Short put option $39.21 $43.00
For the Full Year For the Full Year
of of
Oil contracts (Midland basis differential) 2018 2019
------------------------------------------ ---- ----
Swap contracts
Volume (MBbls) 5,289 -
Weighted average price per Bbl $(0.86) $ -
? For the Full Year For the Full Year
of of
Natural gas contracts 2018 2019
--------------------------------------------------------------------------------------------------------------------------------- ---- ----
Collar contracts (Henry Hub, two-way collars)
Total volume (BBtu) 720 -
Weighted average price per MMBtu
Ceiling (short call option) $3.84 $ -
Floor (long put option) $3.40 $ -
Swap contracts (Henry Hub)
Total volume (BBtu) 3,366 -
Weighted average price per MMBtu $2.95 $ -
Income (Loss) Available to Common Shareholders. The Company reported net income available to common shareholders of $21.0 million for the three months ended December 31, 2017 and Adjusted Income available to common shareholders of $30.2 million, or $0.15 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
December 31, 2017 September 30, 2017 December 31, 2016
----------------- ------------------ -----------------
Income (loss)
available to common
stockholders $21,001 $15,257 $(3,570)
Change in valuation
allowance (8,285) (6,064) 559
Net loss on
derivatives, net of
settlements 16,924 8,416 7,170
Change in the fair
value of share-based
awards 562 475 590
Loss on early
extinguishment of
debt - - 8,374
Adjusted Income $30,202 $18,084 $13,123
======= ======= =======
Adjusted Income per
fully diluted common
share $0.15 $0.09 $0.08
===== ===== =====
Three Months Ended
December 31, 2017 September 30, 2017 December 31, 2016
----------------- ------------------ -----------------
Net income (loss) $22,824 $17,081 $(1,746)
Net loss on
derivatives, net of
settlements 26,037 12,947 11,030
Non-cash stock-based
compensation expense 2,101 1,952 1,718
Loss on early
extinguishment of
debt - - 12,883
Acquisition expense (112) 205 1,263
Income tax expense 248 237 48
Interest expense 461 444 1,369
Depreciation,
depletion and
amortization 37,222 29,132 22,512
Accretion expense 154 131 196
--- --- ---
Adjusted EBITDA $88,935 $62,129 $49,273
======= ======= =======
Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure((i)), for the three months ended December 31, 2017 was $89.0 million and is reconciled to operating cash flow in the following table (in thousands):
Three Months Ended
December 31, 2017 September 30, 2017 December 31, 2016
----------------- ------------------ -----------------
Cash flows from
operating activities:
Net income (loss) $22,824 $17,081 $(1,746)
Adjustments to
reconcile net income
(loss) to cash
provided by operating
activities:
Depreciation,
depletion and
amortization 37,222 29,132 22,512
Accretion expense 154 131 196
Amortization of non-
cash debt related
items 455 441 744
Deferred income tax
expense 247 237 48
Net loss on
derivatives, net of
settlements 26,037 12,947 11,030
Loss on early
extinguishment of
debt - - 9,883
Non-cash expense
related to equity
share-based awards 1,240 1,219 811
Change in the fair
value of liability
share-based awards 865 732 908
--- ---
Discretionary cash
flow $89,044 $61,920 $44,386
======= ======= =======
Changes in working
capital (8,642) (7,777) $(7,832)
Payments to settle
asset retirement
obligations (216) (250) (576)
Net cash provided by
operating activities $80,186 $53,893 $35,978
======= ======= =======
F&D and Reserve Replacement
Calculation 2017
Parameters Metrics
---------- -------
Production (MBOE) (A) 8,373
Proved reserve data
Proved reserves (MBOE)
Total (MBOE) extensions and discoveries (B) 47,375
PUD additions (C) 24,322
PUDs transferred to PDP (D) 8,281
Total annual reserve additions, net of revisions (E) 53,767
Capital costs (in thousands)
Property acquisition costs
Exploration costs $239,453
Development costs 279,424
Unevaluated properties
Exploration costs (F) 6,374
Transfers to evaluated properties (131,170)
Leasehold and seismic 5,006
Total capital costs incurred (G) $389,075
========
Drill-Bit F&D costs per BOE (two-stream) (G) / (B) $8.21
PD F&D per BOE (two-stream) (G - F) / (B - C + D) $12.21
Organic reserve replacement ratio (B) / (A) 566%
All-sources reserve replacement ratio (E) / (A) 642%
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)
December 31, 2017 December 31, 2016
----------------- -----------------
ASSETS
Current assets:
Cash and cash equivalents $27,995 $652,993
Accounts receivable 114,320 69,783
Fair value of derivatives 406 103
Other current assets 2,139 2,247
----- -----
Total current assets 144,860 725,126
------- -------
Oil and natural gas properties, full cost
accounting method:
Evaluated properties 3,429,570 2,754,353
Less accumulated depreciation,
depletion, amortization and
impairment (2,084,095) (1,947,673)
---------- ----------
Net evaluated oil and natural
gas properties 1,345,475 806,680
Unevaluated properties 1,168,016 668,721
--------- -------
Total oil and natural gas
properties, net 2,513,491 1,475,401
--------- ---------
Other property and equipment,
net 20,361 14,114
Restricted investments 3,372 3,332
Deferred tax asset 52 -
Deferred financing costs 4,863 3,092
Acquisition deposit 900 46,138
Other assets, net 5,397 384
----- ---
Total assets $2,693,296 $2,267,587
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued
liabilities $162,878 $95,577
Accrued interest 9,235 6,057
Cash-settleable restricted
stock unit awards 4,621 8,919
Asset retirement obligations 1,295 2,729
Fair value of derivatives 27,744 18,268
------ ------
Total current liabilities 205,773 131,550
------- -------
Senior secured revolving credit
facility 25,000 -
6.125% senior unsecured notes
due 2024, net of unamortized
deferred financing costs 595,196 390,219
Asset retirement obligations 4,725 3,932
Cash-settleable restricted
stock unit awards 3,490 8,071
Deferred tax liability 1,457 90
Fair value of derivatives 1,284 28
Other long-term liabilities 405 295
--- ---
Total liabilities 837,330 534,185
------- -------
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;
201,836,172 and 201,041,320
shares outstanding,
respectively 2,018 2,010
Capital in excess of par value 2,181,359 2,171,514
Accumulated deficit (327,426) (440,137)
-------- --------
Total stockholders' equity 1,855,966 1,733,402
--------- ---------
Total liabilities and
stockholders' equity $2,693,296 $2,267,587
========== ==========
Callon Petroleum Company
Consolidated Statements of Operations
(in thousands, except per share data)
Three Months Ended December 31, Twelve Months Ended December 31,
2017 2016 2017 2016
---- ---- ---- ----
Operating revenues:
Oil sales $104,132 $60,559 $322,374 $177,652
Natural gas sales 14,082 8,522 44,100 23,199
------ ----- ------ ------
Total operating revenues 118,214 69,081 366,474 200,851
Operating expenses:
Lease operating expenses 13,201 14,124 49,907 38,353
Production taxes 6,228 3,717 22,396 11,870
Depreciation, depletion
and amortization 36,543 22,051 115,714 71,369
General and
administrative 8,172 6,562 27,067 26,317
Settled share-based
awards - - 6,351 -
Accretion expense 154 196 677 958
Write-down of oil and
natural gas properties - - - 95,788
Acquisition expense (112) 1,263 2,916 3,673
Total operating expenses 64,186 47,913 225,028 248,328
Income (loss) from
operations 54,028 21,168 141,446 (47,477)
------ ------ ------- -------
Other (income) expenses:
Interest expense, net of
capitalized amounts 461 1,369 2,159 11,871
Loss on early
extinguishment of debt - 12,883 - 12,883
Loss on derivative
contracts 30,536 8,952 18,901 20,233
Other income (41) (338) (1,311) (637)
Total other (income)
expense 30,956 22,866 19,749 44,350
------ ------ ------ ------
Income (loss) before
income taxes 23,072 (1,698) 121,697 (91,827)
Income tax (benefit)
expense 248 48 1,273 (14)
--- --- ----- ---
Net income (loss) 22,824 (1,746) 120,424 (91,813)
Preferred stock
dividends (1,823) (1,824) (7,295) (7,295)
Income (loss) available
to common stockholders $21,001 $(3,570) $113,129 $(99,108)
======= ======= ======== ========
Income (loss) per common share:
Basic $0.10 $(0.02) $0.56 $(0.78)
Diluted $0.10 $(0.02) $0.56 $(0.78)
Shares used in computing income (loss)
per common share:
Basic 201,835 166,258 201,526 126,258
Diluted 202,426 166,258 202,102 126,258
Callon Petroleum Company
Consolidated Statements of Cash Flows
(in thousands)
Three Months Ended December 31, Twelve Months Ended December 31,
2017 2016 2017 2016
---- ---- ---- ----
Cash flows from operating activities:
Net income (loss) $22,824 $(1,746) $120,424 $(91,813)
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation,
depletion and
amortization 37,222 22,512 118,051 73,072
Write-down of oil and
natural gas
properties - - - 95,788
Accretion expense 154 196 677 958
Amortization of non-
cash debt related
items 455 744 2,150 3,115
Deferred income tax
(benefit) expense 247 48 1,273 (14)
Loss on derivatives,
net of settlements 26,037 11,030 10,429 38,135
Loss on sale of other
property and
equipment - - 62 -
Non-cash loss on
early extinguishment
of debt - 9,883 - 9,883
Non-cash expense
related to equity
share-based awards 1,240 811 8,254 2,765
Change in the fair
value of liability
share-based awards 865 908 3,288 6,953
Payments to settle
asset retirement
obligations (216) (576) (2,047) (1,471)
Changes in current assets and
liabilities:
Accounts receivable (32,347) (13,611) (44,495) (30,055)
Other current assets 444 (535) 108 (786)
Current liabilities 23,413 5,473 30,947 25,288
Other long-term
liabilities - 10 121 96
Long-term prepaid - - (4,650) -
Other assets, net (152) 831 (1,528) (840)
Payments for cash-
settled restricted
stock unit awards - - (13,173) (10,300)
--- --- ------- -------
Net cash provided by
operating activities 80,186 35,978 229,891 120,774
------ ------ ------- -------
Cash flows from investing activities:
Capital expenditures (152,621) (67,334) (419,839) (190,032)
Acquisitions (3,952) (352,622) (718,456) (654,679)
Acquisition deposit (900) (13,438) 45,238 (46,138)
Proceeds from sales of
mineral interest and
equipment 20,525 1,639 20,525 24,562
------ ----- ------ ------
Net cash used in
investing activities (136,948) (431,755) (1,072,532) (866,287)
-------- -------- ---------- --------
Cash flows from financing activities:
Borrowings on senior
secured revolving
credit facility 25,000 - 25,000 217,000
Payments on senior
secured revolving
credit facility - - - (257,000)
Payments on term loans - (300,000) - (300,000)
Issuance of 6.125%
senior unsecured
notes due 2024 - 400,000 200,000 400,000
Premium on the
issuance of 6.125%
senior unsecured
notes due 2024 - - 8,250 -
Payment of deferred
financing costs (28) (10,153) (7,194) (10,793)
Issuance of common
stock - 634,862 - 1,357,577
Payment of preferred
stock dividends (1,824) (1,824) (7,295) (7,295)
Tax withholdings
related to restricted
stock units - - (1,118) (2,207)
--- --- ------ ------
Net cash provided by
financing activities 23,148 722,885 217,643 1,397,282
------ ------- ------- ---------
Net change in cash and
cash equivalents (33,614) 327,108 (624,998) 651,769
Balance, beginning of
period 61,609 325,885 652,993 1,224
------ ------- ------- -----
Balance, end of period $27,995 $652,993 $27,995 $652,993
======= ======== ======= ========
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," "Adjusted Total Revenue," "Drill-Bit F&D costs," "PD F&D costs" and "Organic reserve replacement." 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.
-- We believe "Drill-Bit F&D costs," "PD F&D costs" and "Organic reserve
replacement" ratios are non-GAAP metrics commonly used by Callon and
other companies in our industry, as well as analysts and investors, to
measure and evaluate the cost of replenishing annual production and
adding proved reserves. The Company's definitions of "Drill-Bit F&A
costs," "PD F&D costs" and "Organic reserve replacement" may differ
significantly from definitions used by other companies to compute
similar measures and as a result may not be comparable to similar
measures provided by other companies. Consequently, we provided the
detail of our calculation within the included tables.
Earnings Call Information
The Company will host a conference call on Wednesday, February 28, 2018, to discuss fourth quarter and full-year 2017 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: Wednesday, February 28, 2018, at 8:00
a.m. Central Time (9:00 a.m. Eastern
Time)
Webcast: Select "IR Calendar" under the
"Investors" section of the Company's
website: www.callon.com.
Presentation Slides: Select "Presentations" under the
"Investors" section of the Company's
website: www.callon.com.
Alternatively, you may join by telephone using the following numbers:
Domestic: 1-888-317-6003
Canada: 1-866-284-3684
International: 1-412-317-6061
Access code: 2180929
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 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
1-281-589-5279
_________________________________________
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
