Carrizo Oil & Gas, Inc. (Nasdaq: CRZO) today
announced the Company’s financial results for the fourth quarter
and full-year 2017 and provided an operational update, which
includes the following highlights:
- Total production of 62,417 Boe/d,
39% above the fourth quarter of 2016 and above the high-end of the
Company's guidance range
- Crude oil production of 40,206
Bbls/d, 40% above the fourth quarter of 2016
- Net loss attributable to common
shareholders of $23.4 million, or $0.29 per diluted share, and Net
cash provided by operating activities of $142.4 million
- Adjusted net income attributable to
common shareholders of $47.9 million, or $0.58 per diluted share,
and Adjusted EBITDA of $184.1 million
- Adjusted EBITDA margin of $32/Boe,
an increase of 23% versus the prior quarter
- Proved reserves of 261.7 MMBoe, a
31% increase over year-end 2016
- 564% reserve replacement from all
sources at a finding, development, and acquisition (FD&A) cost
of $13.47 per Boe
- 2018 capital expenditure guidance of
$750-$800 million, which reflects an increase in oilfield service
costs
- 2018 production guidance of
58,500-60,100 Boe/d, equivalent to pro forma annual growth of more
than 30%
Carrizo reported fourth quarter of 2017 net loss attributable to
common shareholders of $23.4 million, or $0.29 per basic and
diluted share, compared to a net loss attributable to common
shareholders of $0.8 million, or $0.01 per basic and diluted share
in the fourth quarter of 2016. The net loss attributable to common
shareholders for the fourth quarter of 2017 and the fourth quarter
of 2016 include certain items typically excluded from published
estimates by the investment community. Adjusted net income
attributable to common shareholders, which excludes the impact of
these items as described in the non-GAAP reconciliation tables
included below, for the fourth quarter of 2017 was $47.9 million,
or $0.58 per diluted share, compared to $28.4 million, or $0.44 per
diluted share, in the fourth quarter of 2016.
For the fourth quarter of 2017, Adjusted EBITDA was $184.1
million, an increase of 56% from the prior-year quarter primarily
due to higher production volumes and commodity prices. This
represents the highest level of quarterly Adjusted EBITDA that the
Company has reported. Adjusted EBITDA and the reconciliation to net
income (loss) attributable to common shareholders are presented in
the non-GAAP reconciliation tables included below.
Production volumes during the fourth quarter of 2017 were 5,742
MBoe, or 62,417 Boe/d, an increase of 39% versus the fourth quarter
of 2016. The year-over-year production growth was driven by
drilling activity in the Eagle Ford Shale and Delaware Basin plus
the addition of production from the Sanchez property acquisition in
late 2016 and the ExL property acquisition during the third
quarter, partially offset by the divestiture of the Company's
Appalachian operations during the quarter. Crude oil production
during the fourth quarter of 2017 averaged 40,206 Bbls/d, an
increase of 40% versus the fourth quarter of 2016; natural gas and
NGL production were 78,182 Mcf/d and 9,181 Bbls/d, respectively,
during the fourth quarter of 2017. Fourth quarter of 2017
production exceeded the high end of the Company's guidance range of
60,933-62,200 Boe/d.
Drilling, completion, and infrastructure capital expenditures
for the fourth quarter of 2017 were $210.4 million. Approximately
49% of the fourth quarter drilling, completion, and infrastructure
spending was in the Delaware Basin, while approximately 48% was in
the Eagle Ford Shale. Land and seismic expenditures during the
quarter were $4.5 million, and were primarily focused in the
Delaware Basin.
2017 Proved Reserves
The Company’s proved reserves as of December 31, 2017 were 261.7
MMBoe, a 31% increase over year-end 2016, including 167.4 MMBbls of
crude oil, a 30% increase over year-end 2016. This represents the
highest level of crude oil reserves Carrizo has reported. The
Company’s PV-10 value was $2.6 billion as of December 31, 2017.
The table below summarizes the Company’s year-end 2017 proved
reserves and PV-10 by region as determined by the Company’s
independent reservoir engineers, Ryder Scott Company, L.P., in
accordance with Securities and Exchange Commission guidelines,
using pricing for the twelve months ended December 31, 2017 based
on the West Texas Intermediate benchmark crude oil price of
$51.34/Bbl and the Henry Hub benchmark natural gas price of
$2.98/MMBtu, before adjustment for differentials.
Crude Oil NGLs Natural Gas Total
PV-10 Region (MMBbl)
(MMBbl) (Bcf)
(MMBoe) ($MM) Eagle Ford 124.2 21.7
126.7 167.0 $ 1,871.2 Delaware Basin 40.4 20.4 180.5 90.9 715.0
Niobrara 2.8 0.5 3.3
3.8 52.2
Total 167.4 42.6
310.5 261.7
$ 2,638.4
The table below summarizes the changes in the Company’s proved
reserves during 2017.
Crude Oil NGLs Natural Gas Total
(MMBbl) (MMBbl)
(Bcf) (MMBoe) Proved reserves -
December 31, 2016 128.4 23.9 287.5
200.2 Revisions of previous estimates (19.9 ) (0.9 ) 27.7
(16.1 ) Extensions and discoveries 50.5 13.8 99.0 80.7 Purchases of
reserves in place 21.6 8.6 95.0 46.0 Divestitures of reserves in
place (0.6 ) (0.5 ) (170.2 ) (29.5 ) Production (12.6 )
(2.3 ) (28.5 ) (19.6 )
Proved
reserves - December 31, 2017 167.4
42.6 310.5
261.7 Proved developed - December 31, 2017
69.6 17.5 131.4 109.0
The following table summarizes the Company’s costs incurred in
oil and gas property acquisition, exploration, and development
activities for the year ended December 31, 2017.
Total ($MM) Property acquisition
costs Proved properties $ 303.3 Unproved properties 525.0
Total property acquisition costs 828.3 Exploration costs
91.1 Development costs 570.0
Total costs
incurred (1)
$ 1,489.4
_________
(1) Total costs incurred includes capitalized general and
administrative expense and asset retirement obligations and
excludes capitalized interest.
2017 highlights include:
- Total reserve replacement was 564% at
an all-sources FD&A cost of $13.47 per Boe
- Drill-bit reserve replacement was 330%
at an F&D cost of $10.23 per Boe
- Total proved reserves increased to
261.7 MMBoe, a 31% increase versus year-end 2016
- Eagle Ford reserves increased to 167.0
MMBoe, a 3% increase versus year-end 2016
- Delaware Basin reserves increased to
90.9 MMBoe, a 677% increase versus year-end 2016
- Crude oil represents 64% of total
proved reserves and 83% of the total PV-10 value at December 31,
2017
- Proved developed reserves increased to
109.0 MMBoe at year-end 2017, a 19% increase versus year-end
2016
2018 Capital Program and Guidance
For 2018, Carrizo is providing initial drilling, completion, and
infrastructure capital expenditure guidance of $750-$800 million,
which incorporates an assumed double-digit increase in oilfield
service costs. In recent months, Carrizo has been negotiating with
oilfield service companies, and has currently fixed pricing on
approximately 50% of its services for the majority of 2018. While
the Company expects to partially offset some of the service cost
increase with future efficiency gains, it has not factored these
potential savings into its 2018 capital expenditure guidance.
Carrizo currently plans to operate two rigs in the Eagle Ford Shale
and three to four rigs in the Delaware Basin during 2018, as well
as two to three completion crews during the year. Based on this
level of activity, the Company expects to drill 93-103 gross (82-91
net) operated wells and complete 113-123 gross (96-105 net)
operated wells during the year.
In order to continue driving operational efficiencies, Carrizo
is seeking to complete "multipads" whenever possible in the Eagle
Ford Shale. This incorporates using multiple completion crews
simultaneously to fill in undeveloped areas. During the first
quarter of 2018, Carrizo is completing a 16-well multipad in the
Eagle Ford Shale utilizing three completion crews. In order to
facilitate this, the Company has temporarily moved its Delaware
Basin completion crew to the Eagle Ford Shale. While this
development strategy should result in enhanced project returns, it
is also likely to result in more uneven quarterly production
growth.
In the Delaware Basin, Carrizo plans to allocate approximately
75%-80% of its development activity to its Phantom area, where it
continues to be pleased with the well results it has seen. The
Company expects to drive operational efficiencies in this area
during 2018 by shifting to pad drilling. The remainder of the 2018
development activity is expected to be on the northern portion of
the Company's legacy acreage, where offset operators have recently
drilled strong wells.
The 2018 program also includes approximately $90 million for
infrastructure expenditures. One of the key goals of the Company's
2018 infrastructure program is expanding its water disposal
capacity in the Delaware Basin in order to facilitate the strong
growth it expects from the region. The Company plans to do this via
a combination of Carrizo-owned wells, access to third-party
disposal systems, and eventually recycling. As a result of the 2018
activity, Carrizo currently expects more than a three-fold increase
in its Phantom area water disposal capacity by year-end 2018.
Based on this activity plan, Carrizo is providing initial 2018
production guidance of 58,500-60,100 Boe/d. Crude oil production is
expected to account for 65%-67% of the Company's production for the
year, while total liquids are expected to account for 80%-84%. This
equates to annual production growth of approximately 10% using the
midpoint of the range. Pro forma for the Company's acquisition and
divestiture activity, the 2018 guidance equates to year-over-year
production growth of more than 30%, with crude oil production
growth of more than 20%.
For the first quarter of the year, Carrizo expects production to
be 48,600-49,800 Boe/d; crude oil is expected to account for
65%-67% of production, while total liquids are expected to account
for 80%-84%. First quarter production was negatively impacted by
prolonged freezing temperatures in January. Shut-in production and
operational delays during the month are expected to result in an
impact of 500-600 Boe/d for the first quarter. First quarter
production is also being impacted by the Company's current multipad
development in the Eagle Ford Shale, as these wells are not
expected to have a material impact on production until the second
quarter. As a result, Carrizo expects to see a significant increase
in production between the first and second quarters of the
year.
A full summary of Carrizo’s guidance is provided in the attached
tables.
S.P. “Chip” Johnson, IV, Carrizo’s President and CEO, commented
on the results, “2017 was a transformational year for Carrizo. We
highgraded our portfolio by announcing the divestiture of non-core
assets in the DJ Basin and Appalachia, as well as our downdip
assets in the Eagle Ford Shale, and acquiring a core acreage
position in the Delaware Basin. This leaves us with a deep
inventory of core locations in two of the highest-return basins in
North America, the Eagle Ford Shale and Delaware Basin. We believe
these assets are highly complementary. The Eagle Ford Shale is
currently free cash flow positive at the field level, and we are
able to use this excess cash flow to help fund the strong growth we
expect to deliver from the Delaware Basin. At the corporate level,
we remain committed to achieving cash flow neutrality and expect to
be able to deliver this by the fourth quarter of 2018 at an oil
price of $55-$60/Bbl, while still generating strong production
growth.
“We remain pleased with the results we have seen from our
Phantom area acreage in the Delaware Basin. During the fourth
quarter, we continued to deliver strong results from both the
Wolfcamp A and Wolfcamp B, with multiple wells delivering peak
three-stream 90-day rates in excess of 1,500 Boe/d. Our production
from the area is currently constrained by water takeaway capacity
via pipeline, but we expect this to be remedied by next quarter,
and expect significant growth after that. While our 2018
development program is expected to remain focused on the Wolfcamp A
and B, we also plan to test the Wolfcamp C during the year.
“The fourth quarter was another excellent quarter for the
Company. Production increased by 13% and exceeded our guidance,
price realizations were stronger than expected as our Eagle Ford
production benefited from the LLS premium to WTI, and operating
costs were in the lower half of our expected range. As a result,
our Adjusted EBITDA margin expanded by more than 20% versus the
prior quarter.
“During 2017, we once again delivered strong reserve growth.
This was led by the Delaware Basin, where proved reserves increased
by more than 675% during the year, and now account for
approximately 35% of our total proved reserves, up from just 6% at
year-end 2016. As a result, we were able to increase our total
proved reserves by more than 30% during the year.”
Operational Update
In the Eagle Ford Shale, Carrizo drilled 20 gross (16 net)
operated wells during the fourth quarter and completed 14 gross (13
net) operated wells. Production from the play was approximately
41,600 Boe/d, a 7% increase versus the prior quarter. Crude oil
production was more than 31,900 Bbls/d, accounting for
approximately 77% of the Company's production from the play. During
the fourth quarter, Carrizo turned 21 net wells to sales in the
Eagle Ford Shale, which had an average lateral length of
approximately 7,000 ft. The average peak 30-day rate from these
wells was approximately 700 Boe/d (88% oil, 94% liquids) on
restricted chokes. At the end of the quarter, Carrizo had 37 gross
(31 net) operated Eagle Ford Shale wells in progress or waiting on
completion, equating to net crude oil production potential of more
than 11,700 Bbls/d. The Company is currently operating two rigs in
the Eagle Ford Shale, and expects to drill 60-65 gross (56-61 net)
operated wells and complete 80-85 gross (71-76 net) operated wells
in the play during 2018.
Subsequent to the sale of its Tier 1 assets in January, Carrizo
sees more than 700 net remaining locations in the Core of the Eagle
Ford Shale spaced at 330-500 ft., depending upon the geologic
characteristics of the specific project areas. An additional
100-150 net locations have also been identified at tighter well
spacing in areas the Company has currently tested. While still
profitable, the cash flow profile from these wells is not
consistent with Carrizo's free cash flow target and as such, the
Company does not currently plan on drilling additional
stagger-stack development wells in 2018 at forecasted commodity
price and oilfield service cost levels. The Company does plan to
continue to test wells spaced tighter than 330 ft. with stage
spacing as short as 150 ft., as outlined below. Additionally,
Carrizo has been successful in its efforts to extend the average
lateral length of its future wells. While longer laterals are
expected to enhance the returns generated by the Company's Eagle
Ford Shale position, they also result in an approximate 5%
reduction in the future well count.
As the Company’s number of producing wells continues to grow,
and a larger percentage of new wells are drilled in areas with
significant existing production, Carrizo has seen an increased
impact from parent-child relationships on the new wells immediately
offsetting the existing wells. This has also resulted in a higher
ratio of existing wells requiring shut-in during completion
operations as well as longer shut-in periods in some instances. In
order to minimize these impacts, the Company plans to move to a
multipad development whenever possible in the Eagle Ford Shale.
This involves using multiple completion crews simultaneously to
complete a large number of wells on multiple contiguous pads,
thereby reducing future parent-child impacts. This should lead to
higher average EURs over time for the new wells and less downtime
for the parent wells. The Company's initial multipad is
located in its Brown Trust area. The multipad includes 16 wells on
three pads, with well spacing of 250-330 ft., and frac stage
spacing of 150-180 ft. Production from the multipad is expected to
begin in late March, and should reach gross oil rates of more than
10,000 Bbls/d once all of the wells are online.
Carrizo has been testing multiple concepts in order to optimize
its completion design in the Eagle Ford Shale, including tighter
stage spacing, increased proppant, and amount and type of fluid. To
date, the data indicates that tighter stage spacing is resulting in
improved performance, while data on the other variables appears
less conclusive. As a result of the Company's completion
optimization work, it has seen more than a 10% improvement in the
lateral-normalized performance of its 2017 wells relative to its
2016 wells. Carrizo has recently been testing stage spacing as
tight as 150 ft., with the tighter-stage-spaced wells continuing to
outperform nearby wells with wider stage spacing. In a recent test
in the Company's North LaSalle area, two pads completed with
150-180 ft. stage spacing are outperforming the area typecurve by
15%-20% after approximately 110 days.
In the Delaware Basin, Carrizo drilled 9 gross (7 net) operated
wells during the fourth quarter and completed 9 gross (7 net)
operated wells. Production from the play was more than 15,100 Boe/d
for the quarter, up more than 115% versus the prior quarter as a
number of new wells were brought online and the Company got the
benefit of a full quarter of production from the ExL acquisition.
Crude oil production was approximately 6,500 Bbls/d, accounting for
approximately 43% of the Company's production from the play. At the
end of the quarter, Carrizo had 6 gross (5 net) operated Delaware
Basin wells in progress or waiting on completion. The Company is
currently operating four rigs in the Delaware Basin, but plans to
reduce this to three later in the year. Carrizo expects to drill
33-38 gross (26-30 net) operated wells and complete 33-38 gross
(25-29 net) operated wells in the play during 2018.
In the Phantom area, Carrizo continued to focus on the Wolfcamp
B in order to further confirm its productivity across the acreage
as well as ensure all depths were held. To date, more than 75% of
the wells the Company has drilled since acquiring the asset have
targeted the Wolfcamp B. Carrizo has been very pleased with the
results it has seen, as production from the wells has met targeted
levels, but with higher flowing wellhead pressures than expected.
This could lead to a shallower decline than the Company is
currently assuming in its Wolfcamp B typecurve.
While the production from the Wolfcamp B wells has been very
encouraging, the wells have also produced at a higher initial
water-oil-ratio than Wolfcamp A wells, resulting in produced water
volumes temporarily exceeding the Company’s acquisition forecast.
Delays in forecasted upgrade projects to third-party disposal
systems combined with these higher volumes have resulted in the
Company’s production being temporarily constrained by the available
water-takeaway infrastructure. Carrizo has been working diligently
to alleviate this bottleneck by putting firm agreements in place
with third-party providers in addition to installing a
company-owned water management system; combined, this should allow
Carrizo to double its water takeaway capacity by the beginning of
the second quarter and more than triple it by year-end. While the
infrastructure bottleneck has delayed the Company's planned
production ramp in the basin by a quarter, Carrizo expects to have
the infrastructure in place to support significant production
growth from the area during 2018.
Hedging Activity
Carrizo currently has hedges in place for approximately 75% of
estimated crude oil production for 2018 (based on the midpoint of
guidance). For the year, Carrizo currently has hedges covering
30,000 Bbls/d of crude oil production, consisting of three-way
collars covering 24,000 Bbls/d of crude oil with an average floor
price of $49.06/Bbl, ceiling price of $60.14/Bbl, and sub-floor
price of $39.38/Bbl, and swaps covering 6,000 Bbls/d at an average
fixed price of $49.55/Bbl. For 2019, Carrizo currently has
three-way collars covering 12,000 Bbls/d of crude oil with an
average floor price of $48.40/Bbl, ceiling price of $60.29/Bbl, and
sub-floor price of $40.00/Bbl.
Carrizo has hedges in place for more than 50% of estimated NGL
production for 2018. For the year, Carrizo has swaps covering 2,200
Bbls/d of ethane, 1,500 Bbls/d of propane, 200 Bbls/d of butane,
600 Bbls/d of isobutane, and 600 Bbls/d of natural gasoline at
average fixed prices of $12.01/Bbl, $34.23/Bbl, $38.85/Bbl,
$38.98/Bbl, and $55.23/Bbl, respectively.
Carrizo also has hedges in place for approximately 35% of
estimated natural gas production for 2018. For March 2018-December
2018, the Company has swaps covering 25,000 MMBtu/d of natural gas
at an average fixed price of $3.01/MMBtu. (Please refer to the
attached tables for details of the Company’s derivative
contracts.)
Conference Call Details
The Company will hold a conference call to discuss 2017 fourth
quarter financial results on Tuesday, February 27, 2018 at 10:00 AM
Central Standard Time. To participate in the call, please dial
(877) 256-3271 (U.S. & Canada) or +1 (212) 231-2939
(Intl.) ten minutes before the call is scheduled to begin. A replay
of the call will be available through Tuesday, March 6, 2018 at
12:00 PM Central Standard Time at (800) 633-8284 (U.S. &
Canada) or +1 (402) 977-9140 (Intl.). The reservation number
for the replay is 21882319 for U.S., Canadian, and International
callers.
A simultaneous webcast of the call may be accessed over the
internet by visiting the Carrizo website at http://www.carrizo.com, clicking on “Upcoming
Events”, and then clicking on the “Fourth Quarter 2017 Earnings
Call” link. To listen, please go to the website in time to register
and install any necessary software. The webcast will be archived
for replay on the Carrizo website for 7 days. A slide deck will
also be posted to the website to accompany the conference call.
Carrizo Oil & Gas, Inc. is a Houston-based energy company
actively engaged in the exploration, development, and production of
oil and gas from resource plays located in the United States. Our
current operations are principally focused in proven, producing oil
and gas plays primarily in the Eagle Ford Shale in South Texas and
the Permian Basin in West Texas.
Statements in this release that are not historical facts,
including but not limited to those related to capital requirements,
free cash flow positive program, the ExL acquisition (including
effects thereof), dispositions, contingent payment amounts,
monetization process matters and results, capital expenditure,
infrastructure program, guidance, rig program, production, average
well returns, the estimated production results and financial
performance, effects of transactions, targeted ratios and other
metrics, timing, levels of and potential production, expectations
regarding significant growth, expectations regarding higher average
EURs, downspacing, crude oil production potential and growth, oil
and gas prices, drilling and completion activities, drilling
inventory, including timing thereof, well costs, break-even prices,
production mix, development plans, growth, hedging activity, the
Company’s or management’s intentions, beliefs, expectations, hopes,
projections, assessment of risks, estimations, plans or predictions
for the future, results of the Company’s strategies and other
statements that are not historical facts are forward-looking
statements that are based on current expectations. Although the
Company believes that its expectations are based on reasonable
assumptions, it can give no assurance that these expectations will
prove correct. Important factors that could cause actual results to
differ materially from those in the forward-looking statements
include assumptions regarding well costs, estimated recoveries,
pricing and other factors affecting average well returns, results
of wells and testing, failure of actual production to meet
expectations, failure of infrastructure program, failure to reach
significant growth, failure to reach higher average EURs,
performance of rig operators, spacing test results, availability of
gathering systems, costs of oilfield services, actions by
governmental authorities, joint venture partners, industry
partners, lenders and other third parties, actions by purchasers or
sellers of properties, satisfaction of closing conditions and
failure of transactions to close, purchase price adjustment,
integration and other risks and effects of acquisitions and
dispositions, market and other conditions, risks regarding
financing, capital needs, availability of well connects, capital
needs and uses, commodity price changes, effects of the global
economy on exploration activity, results of and dependence on
exploratory drilling activities, operating risks, right-of-way and
other land issues, availability of capital and equipment, weather,
and other risks described in the Company’s Form 10-K for the year
ended December 31, 2016 and its other filings with the U.S.
Securities and Exchange Commission. There can be no assurance any
transaction described in this press release will occur on the terms
or timing described, or at all.
(Financial Highlights to Follow)
CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE
SHEETS (In thousands, except share and per share
amounts) (Unaudited)
December 31, 2017
December 31, 2016
Assets Current assets Cash and cash equivalents $ 9,540 $
4,194 Accounts receivable, net 107,441 64,208 Other current assets
5,897 4,586 Total current assets
122,878 72,988 Property and equipment Oil and
gas properties, full cost method Proved properties, net 1,965,347
1,294,667 Unproved properties, not being amortized 660,287 240,961
Other property and equipment, net 10,176
10,132 Total property and equipment, net 2,635,810 1,545,760
Other assets 19,616 7,579
Total
Assets $ 2,778,304 $ 1,626,327
Liabilities and Shareholders’ Equity Current liabilities
Accounts payable $ 74,558 $ 55,631 Revenues and royalties payable
52,154 38,107 Accrued capital expenditures 119,452 36,594 Accrued
interest 28,362 22,016 Accrued lease operating expense 18,223
12,377 Derivative liabilities 57,121 22,601 Other current
liabilities 22,952 24,633 Total current
liabilities 372,822 211,959 Long-term
debt 1,629,209 1,325,418 Asset retirement obligations 23,497 20,848
Derivative liabilities 112,332 27,528 Deferred income taxes 3,635 —
Other liabilities 51,650 17,116 Total
liabilities 2,193,145 1,602,869
Commitments and contingencies Preferred Stock
Preferred stock, $0.01 par value,
10,000,000 shares authorized; 250,000 issued and outstanding as of
December 31, 2017 and none issued and outstanding as of December
31, 2016
214,262 —
Shareholders’ equity Common stock, $0.01 par
value, 180,000,000 shares authorized; 81,454,621 issued and
outstanding as of December 31, 2017 and 90,000,000 shares
authorized; 65,132,499 issued and outstanding as of December 31,
2016 815 651 Additional paid-in capital 1,926,056 1,665,891
Accumulated deficit (1,555,974 ) (1,643,084 ) Total
shareholders’ equity 370,897 23,458
Total Liabilities and Shareholders’ Equity $ 2,778,304
$ 1,626,327
CARRIZO OIL & GAS,
INC.CONSOLIDATED STATEMENTS OF OPERATIONS(In
thousands, except per share amounts)(Unaudited)
Three Months EndedDecember 31, Years
EndedDecember 31, 2017 2016 2017
2016 Revenues Crude oil $ 210,234 $ 123,315 $ 633,233
$ 378,073 Natural gas liquids 19,727 7,309 47,405 22,428 Natural
gas 16,810 13,207 65,250
43,093 Total revenues 246,771 143,831 745,888 443,594
Costs and Expenses Lease operating 39,087 27,646
139,854 98,717 Production taxes 11,417 6,106 32,509 19,046 Ad
valorem taxes 1,491 1,609 7,267 5,559 Depreciation, depletion and
amortization 81,571 53,470 262,589 213,962 General and
administrative, net 16,901 15,926 66,229 74,972 (Gain) loss on
derivatives, net 86,107 19,135 59,103 49,073 Interest expense, net
18,520 20,490 80,870 79,403 Impairment of proved oil and gas
properties — — — 576,540 Loss on extinguishment of debt 4,170 —
4,170 — Other expense, net 517 228
2,157 1,796 Total costs and expenses
259,781 144,610 654,748 1,119,068
Income (Loss) Before
Income Taxes (13,010 ) (779 ) 91,140 (675,474 ) Income tax
expense (4,030 ) — (4,030 ) —
Net Income (Loss) ($17,040 ) ($779 ) $
87,110 ($675,474 ) Dividends on preferred stock
(5,532 ) — (7,781 ) — Accretion on preferred stock (862 )
— (862 ) —
Net Income (Loss)
Attributable to Common Shareholders ($23,434 )
($779 ) $ 78,467 ($675,474 )
Net
Income (Loss) Attributable to Common Shareholders Per Common
Share Basic ($0.29 ) ($0.01 ) $ 1.07 ($11.27 ) Diluted ($0.29 )
($0.01 ) $ 1.06 ($11.27 )
Weighted Average Common Shares
Outstanding Basic 81,415 63,587 73,421 59,932 Diluted 81,415
63,587 73,993 59,932
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (In
thousands, except share amounts) (Unaudited)
Common Stock AdditionalPaid-in
Capital
Accumulated Deficit
TotalShareholders’ Equity Shares
Amount Balance as of December 31, 2016 65,132,499 $
651 $ 1,665,891 ($1,643,084 ) $ 23,458 Stock-based compensation
expense — — 23,625 — 23,625 Issuance of common stock upon grants of
restricted stock awards and vestings of restricted stock units and
performance shares 722,122 8 (42 ) — (34 ) Sale of common stock,
net of offering costs 15,600,000 156 222,222 — 222,378 Issuance of
warrants — — 23,003 — 23,003 Dividends on preferred stock — —
(7,781 ) — (7,781 ) Accretion on preferred stock — — (862 ) — (862
) Net income — — — 87,110
87,110
Balance as of December 31, 2017
81,454,621 $ 815 $ 1,926,056 ($1,555,974 ) $
370,897
CARRIZO OIL & GAS,
INC.CONSOLIDATED STATEMENTS OF CASH FLOWS(In
thousands)(Unaudited)
Three Months EndedDecember
31, Years EndedDecember 31, 2017
2016 2017 2016 Cash Flows From Operating
Activities Net income (loss) ($17,040 ) ($779 ) $ 87,110
($675,474 ) Adjustments to reconcile net income (loss) to net cash
provided by operating activities Depreciation, depletion and
amortization 81,571 53,470 262,589 213,962 Impairment of proved oil
and gas properties — — — 576,540 (Gain) loss on derivatives, net
86,107 19,135 59,103 49,073 Cash received for derivative
settlements, net 59 20,549 7,773 119,369 Loss on extinguishment of
debt 4,170 — 4,170 — Stock-based compensation expense, net 5,847
5,252 14,309 36,086 Deferred income taxes 3,635 — 3,635 — Non-cash
interest expense, net 696 1,067 3,657 4,172 Other, net (1,912 )
1,326 2,337 3,753 Changes in components of working capital and
other assets and liabilities- Accounts receivable (15,745 ) (14,604
) (41,630 ) (12,836 ) Accounts payable (2,926 ) (9,836 ) 11,822
(30,130 ) Accrued liabilities (458 ) 16 11,512 (7,938 ) Other
assets and liabilities, net (1,620 ) (675 )
(3,406 ) (3,809 ) Net cash provided by operating activities
142,384 74,921 422,981
272,768
Cash Flows From Investing Activities
Capital expenditures (221,150 ) (134,684 ) (654,711 ) (480,929 )
Acquisitions of oil and gas properties (3,768 ) (153,521 ) (695,774
) (153,521 ) Net proceeds from divestitures of oil and gas
properties 173,152 233 197,564 15,564 Other, net (2,727 )
(285 ) (6,531 ) (946 ) Net cash used in
investing activities (54,493 ) (288,257 )
(1,159,452 ) (619,832 )
Cash Flows From Financing
Activities Issuance of 8.25% Senior Notes due 2025 — — 250,000
— Redemption of 7.50% Senior Notes due 2020 (152,813 ) — (152,813 )
— Borrowings under credit agreement 680,648 260,175 1,992,523
770,291 Repayments of borrowings under credit agreement (604,948 )
(269,175 ) (1,788,223 ) (683,291 ) Payments of debt issuance costs
and credit facility amendment fees (87 ) (180 ) (9,051 ) (1,330 )
Sale of common stock, net of offering costs — 223,739 222,378
223,739 Sale of preferred stock, net of issuance costs — — 236,404
— Payment of dividends on preferred stock (5,532 ) — (7,781 ) —
Other, net (711 ) (264 ) (1,620 )
(1,069 ) Net cash provided by (used in) financing activities
(83,443 ) 214,295 741,817
308,340
Net Increase (Decrease) in Cash and Cash
Equivalents 4,448 959 5,346 (38,724 )
Cash and Cash
Equivalents, Beginning of Period 5,092
3,235 4,194 42,918
Cash and
Cash Equivalents, End of Period $ 9,540 $ 4,194 $
9,540 $ 4,194
CARRIZO OIL & GAS, INC.
NON-GAAP FINANCIAL MEASURES
(Unaudited)
Reconciliation of Net Income (Loss) Attributable to Common
Shareholders (GAAP) to Adjusted Net Income Attributable to Common
Shareholders (Non-GAAP)
Adjusted net income attributable to common shareholders is a
non-GAAP financial measure which excludes certain items that are
included in net income (loss) attributable to common shareholders,
the most directly comparable GAAP financial measure. Items excluded
are those which the Company believes affect the comparability of
operating results and are typically excluded from published
estimates by the investment community, including items whose timing
and/or amount cannot be reasonably estimated or are
non-recurring.
Adjusted net income attributable to common shareholders is
presented because management believes it provides useful additional
information to investors for analysis of the Company’s fundamental
business on a recurring basis. In addition, management believes
that adjusted net income attributable to common shareholders is
widely used by professional research analysts and others in the
valuation, comparison, and investment recommendations of companies
in the oil and gas exploration and production industry.
Adjusted net income attributable to common shareholders should
not be considered in isolation or as a substitute for net income
(loss) attributable to common shareholders or any other measure of
a company’s financial performance or profitability presented in
accordance with GAAP. A reconciliation of the differences between
net income (loss) attributable to common shareholders and adjusted
net income attributable to common shareholders is presented below.
Because adjusted net income attributable to common shareholders
excludes some, but not all, items that affect net income (loss)
attributable to common shareholders and may vary among companies,
our calculation of adjusted net income attributable to common
shareholders may not be comparable to similarly titled measures of
other companies.
Three Months
EndedDecember 31, Years EndedDecember 31,
2017 2016 2017 2016 (In thousands,
except per share amounts) Net Income (Loss) Attributable to
Common Shareholders (GAAP) ($23,434 ) ($779 ) $ 78,467
($675,474 ) Income tax expense 4,030 — 4,030 — (Gain) loss on
derivatives, net 86,107 19,135 59,103 49,073 Cash received for
derivative settlements, net 59 20,549 7,773 119,369 Non-cash
general and administrative, net 6,194 5,025 15,284 36,009
Impairment of proved oil and gas properties — — — 576,540 Loss on
extinguishment of debt 4,170 — 4,170 — Other expense, net
517 228 2,157 618
Adjusted income before income taxes 77,643 44,158 170,984 106,135
Adjusted income tax expense (1) (29,737 ) (15,720 )
(65,487 ) (37,784 )
Adjusted Net Income
Attributable to Common Shareholders (Non-GAAP) $ 47,906
$ 28,438 $ 105,497 $ 68,351
Net
Income (Loss) Attributable to Common Shareholders Per Diluted
Common Share (GAAP) ($0.29 ) ($0.01 ) $ 1.06 ($11.27 ) Income
tax expense 0.05 — 0.05 — (Gain) loss on derivatives, net 1.05 0.30
0.80 0.81 Cash received for derivative settlements, net — 0.32 0.11
1.97 Non-cash general and administrative, net 0.08 0.08 0.21 0.60
Impairment of proved oil and gas properties — — — 9.51 Loss on
extinguishment of debt 0.05 — 0.06 — Other expense, net 0.01 — 0.02
0.01 Effect of dilutive securities due to adjusted net income
attributable to common shareholders — —
— 0.12
(2)
Adjusted income before income taxes 0.95 0.69 2.31 1.75 Adjusted
income tax expense (0.37 ) (0.25 ) (0.88 )
(0.62 )
Adjusted Net Income Attributable to Common
Shareholders Per Diluted Common Share (Non-GAAP) $ 0.58
$ 0.44 $ 1.43 $ 1.13
Diluted WASO
(GAAP) 81,415 63,587 73,993 59,932 Dilutive shares adjustment
656 717 — 668
Adjusted Diluted WASO (Non-GAAP) 82,071
(2)
64,304
(2)
73,993 60,600
(2)
___________
(1) Adjusted income tax expense is calculated by
applying the Company’s estimated annual effective income tax rates
applicable to the adjusted income before income taxes, which were
38.3% for the three months and year ended December 31, 2017 and
35.6% for the three months and year ended December 31, 2016. (2)
Adjusted diluted weighted average common shares outstanding
(“Adjusted Diluted WASO”) is a non-GAAP financial measure which
includes the effect of potentially dilutive instruments that, under
certain circumstances described below, are excluded from diluted
weighted average common shares outstanding (“Diluted WASO”), the
most directly comparable GAAP financial measure. When a net loss
attributable to common shareholders exists, all potentially
dilutive instruments are anti-dilutive to the net loss attributable
to common shareholders per common share and therefore excluded from
the computation of Diluted WASO. The effect of potentially dilutive
instruments is included in the computation of Adjusted Diluted WASO
for purposes of computing the per diluted common share impacts of
the reconciling items as well as adjusted net income attributable
to common shareholders per diluted common share.
CARRIZO OIL & GAS, INC.
NON-GAAP FINANCIAL MEASURES
(Unaudited)
Reconciliation of Net Income (Loss) Attributable to Common
Shareholders (GAAP) to Adjusted EBITDA (Non-GAAP) to Net Cash
Provided by Operating Activities (GAAP)
Adjusted EBITDA is a non-GAAP financial measure which excludes
certain items that are included in net income (loss) attributable
to common shareholders, the most directly comparable GAAP financial
measure. Items excluded are interest, income taxes, depreciation,
depletion and amortization, impairments, dividends and accretion on
preferred stock and items that the Company believes affect the
comparability of operating results such as items whose timing
and/or amount cannot be reasonably estimated or are
non-recurring.
Adjusted EBITDA is presented because management believes it
provides useful additional information to investors and analysts,
for analysis of the Company’s financial and operating performance
on a recurring basis and the Company’s ability to internally
generate funds for exploration and development, and to service
debt. In addition, management believes that adjusted EBITDA is
widely used by professional research analysts and others in the
valuation, comparison, and investment recommendations of companies
in the oil and gas exploration and production industry.
Adjusted EBITDA should not be considered in isolation or as a
substitute for net income (loss) attributable to common
shareholders, net cash provided by operating activities, or any
other measure of a company’s profitability or liquidity presented
in accordance with GAAP. A reconciliation of net income (loss)
attributable to common shareholders to adjusted EBITDA to net cash
provided by operating activities is presented below. Because
adjusted EBITDA excludes some, but not all, items that affect net
income (loss) attributable to common shareholders, our calculations
of adjusted EBITDA may not be comparable to similarly titled
measures of other companies.
Reconciliation of Net Cash Provided by Operating Activities
(GAAP) to Discretionary Cash Flows (Non-GAAP)
Discretionary cash flows are a non-GAAP financial measure which
excludes certain items that are included in net cash provided by
operating activities, the most directly comparable GAAP financial
measure. Items excluded are changes in the components of working
capital and other items that the Company believes affect the
comparability of operating cash flows such as items that are
non-recurring.
Discretionary cash flows are presented because management
believes it provides useful additional information to investors for
analysis of the Company’s ability to generate cash to fund
exploration and development, and to service debt. In addition,
management believes that discretionary cash flows is widely used by
professional research analysts and others in the valuation,
comparison, and investment recommendations of companies in the oil
and gas exploration and production industry.
Discretionary cash flows should not be considered in isolation
or as a substitute for net cash provided by operating activities or
any other measure of a company’s cash flows or liquidity presented
in accordance with GAAP. A reconciliation of net cash provided by
operating activities to discretionary cash flows is presented
below. Because discretionary cash flows excludes some, but not all,
items that affect net cash provided by operating activities and may
vary among companies, our calculation of discretionary cash flows
may not be comparable to similarly titled measures of other
companies.
Three Months
EndedDecember 31, Years EndedDecember 31,
2017 2016 2017
2016 (In thousands) Net Income (Loss) Attributable
to Common Shareholders (GAAP) ($23,434 ) ($779 ) $ 78,467
($675,474 ) Dividends on preferred stock 5,532 — 7,781 — Accretion
on preferred stock 862 — 862 — Income tax expense 4,030 — 4,030 —
Depreciation, depletion and amortization 81,571 53,470 262,589
213,962 Interest expense, net 18,520 20,490 80,870 79,403 (Gain)
loss on derivatives, net 86,107 19,135 59,103 49,073 Cash received
for derivative settlements, net 59 20,549 7,773 119,369 Non-cash
general and administrative, net 6,194 5,025 15,284 36,009
Impairment of proved oil and gas properties — — — 576,540 Loss on
extinguishment of debt 4,170 — 4,170 — Other expense, net
517 228 2,157 618
Adjusted EBITDA (Non-GAAP) $ 184,128 $ 118,118 $ 523,086 $
399,500 Cash interest expense, net (17,824 ) (19,423 ) (77,213 )
(75,231 ) Cash dividends on preferred stock (5,532 ) — (7,781 ) —
Other cash and non-cash adjustments, net (3,171 ) 999
(1,190 ) 2,986
Discretionary Cash
Flows (Non-GAAP) $ 157,601 $ 99,694 $ 436,902 $ 327,255 Changes
in components of working capital and other (15,217 )
(24,773 ) (13,921 ) (54,487 )
Net Cash Provided By
Operating Activities (GAAP) $ 142,384 $ 74,921 $
422,981 $ 272,768
Adjusted EBITDA margin as presented in the press release above
is calculated as Adjusted EBITDA divided by total production for
the respective period.
CARRIZO OIL & GAS, INC.
NON-GAAP FINANCIAL MEASURES
(Unaudited)
Reconciliation of Standardized Measure of Discounted Future
Net Cash Flows (GAAP) to PV-10 (Non-GAAP)
PV-10 is a non-GAAP financial measure which excludes the present
value of future income taxes discounted at 10% per annum, which is
included in the standardized measure of discounted future net cash
flows, the most directly comparable GAAP financial measure.
PV-10 is presented because management believes it provides
greater comparability when evaluating oil and gas companies due to
the many factors unique to each individual company that impact the
amount and timing of future income taxes. In addition, management
believes that PV-10 is widely used by investors and analysts as a
basis for comparing the relative size and value of the Company’s
proved reserves to other oil and gas companies.
PV-10 should not be considered in isolation or as a substitute
for the standardized measure of discounted future net cash flows or
any other measure of a company’s financial or operating performance
presented in accordance with GAAP. A reconciliation of the
standardized measure of discounted future net cash flows to PV-10
is presented below.
As of December 31, 2017 (In millions)
Standardized measure of discounted future net cash flows
(GAAP) $ 2,465.1 Add: present value of future income taxes
discounted at 10% per annum 173.3
PV-10 (Non-GAAP) $
2,638.4
Reserve Replacement (Non-GAAP)
Reserve replacement is a non-GAAP metric commonly used by the
Company, as well as analysts and investors, to evaluate the
Company’s ability to replenish annual production and grow its
proved reserves. Total reserve replacement and drill-bit reserve
replacement can be computed from information provided in this press
release.
Total reserve replacement is defined as the sum of proved
reserve extensions and discoveries, revisions of previous estimates
and purchases of reserves in place divided by production for the
corresponding period. Drill-bit reserve replacement is defined as
the sum of proved reserve extensions and discoveries and revisions
of previous estimates divided by production for the corresponding
period. These definitions of reserve replacement may differ
significantly from definitions used by other companies to compute
similar measures. As a result, reserve replacement as defined above
may not be comparable to similar measures provided by other
companies.
Reserve replacement is limited because it typically varies
widely based on the extent and timing of new discoveries and
property acquisitions. Its predictive and comparative value is also
limited for the same reasons. Reserve replacement does not
distinguish between changes in reserve quantities that are
producing and those that will require additional time and capital
to begin producing. In addition, since reserve replacement does not
take into consideration the cost or timing of future production of
new reserves, it cannot be used as a measure of value creation.
Finding and Development Costs (Non-GAAP)
Finding and development ("F&D") costs are non-GAAP metrics
commonly used by the Company, as well as analysts and investors, to
measure and evaluate the Company’s cost of adding proved reserves.
The all sources finding, development, and acquisition (“FD&A”)
cost and drill-bit F&D cost can be computed from information
provided in this press release.
All sources FD&A cost is defined as the sum of exploration
costs, development costs and property acquisition costs divided by
the sum of proved reserve extensions and discoveries, revisions of
previous estimates and purchases of reserves in place. Drill-bit
F&D cost is defined as the sum of exploration costs and
development costs divided by the sum of proved reserve extensions
and discoveries and revisions of previous estimates. These
definitions of all sources FD&A costs and drill-bit F&D
costs may differ significantly from definitions used by other
companies to compute similar measures. As a result, the all sources
FD&A costs and drill-bit F&D costs defined above may not be
comparable to similar measures provided by other companies.
Due to various factors, including timing differences, F&D
costs do not necessarily reflect precisely the costs associated
with particular reserves. For example, development costs may be
recorded in periods before or after the periods in which the
related reserves are recorded. In addition, changes in commodity
prices can affect the magnitude of recorded increases or decreases
in reserves independent of the related cost of such increases.
CARRIZO OIL & GAS, INC. PRODUCTION VOLUMES AND
REALIZED PRICES (Unaudited)
Three Months EndedDecember
31,
Years EndedDecember 31, 2017
2016 2017 2016 Total production volumes
- Crude oil (MBbls) 3,699 2,643 12,566 9,423 NGLs (MBbls) 845
464 2,327 1,788 Natural gas (MMcf) 7,193 6,072
28,472 25,574
Total barrels of oil
equivalent (MBoe) 5,742 4,119
19,639 15,473
Daily production
volumes by product - Crude oil (Bbls/d) 40,206 28,727 34,428
25,745 NGLs (Bbls/d) 9,181 5,048 6,376 4,885 Natural gas (Mcf/d)
78,182 65,999 78,006
69,873
Total barrels of oil equivalent (Boe/d)
62,417 44,775 53,805
42,276
Daily production volumes by region (Boe/d) -
Eagle Ford 41,555 32,339 37,825 30,664 Delaware Basin 15,145 2,469
6,713 1,115 Niobrara 2,353 3,190 2,558 2,931 Marcellus 3,115 5,965
6,122 6,329 Utica and other 249 812
587 1,237
Total barrels of oil equivalent
(Boe/d) 62,417 44,775 53,805
42,276
Realized prices - Crude oil ($
per Bbl) $ 56.84 $ 46.66 $ 50.39 $ 40.12 NGLs ($ per Bbl) $ 23.35 $
15.75 $ 20.37 $ 12.54 Natural gas ($ per Mcf) $ 2.34 $ 2.18 $ 2.29
$ 1.69
CARRIZO OIL & GAS, INC. COMMODITY
DERIVATIVE CONTRACTS - AS OF FEBRUARY 23, 2018
(Unaudited)
CRUDE OIL (1)
Volume Sub-Floor Price Floor Price Ceiling
Price Period Type of Contract (Bbls/d)
($/Bbl) ($/Bbl) ($/Bbl) Q1 2018 Fixed Price
Swaps 6,000 $49.55 Three-Way Collars 24,000 $39.38 $49.06 $60.14
Net Sold Call Options 3,388 $71.33 Q2 2018 Fixed Price Swaps
6,000 $49.55 Three-Way Collars 24,000 $39.38 $49.06 $60.14 Net Sold
Call Options 3,388 $71.33 Q3 2018 Fixed Price Swaps 6,000
$49.55 Three-Way Collars 24,000 $39.38 $49.06 $60.14 Net Sold Call
Options 3,388 $71.33 Q4 2018 Fixed Price Swaps 6,000 $49.55
Three-Way Collars 24,000 $39.38 $49.06 $60.14 Net Sold Call Options
3,388 $71.33 FY 2019 Three-Way Collars 12,000 $40.00 $48.40
$60.29 Net Sold Call Options 3,875 $73.66 FY 2020 Net Sold
Call Options 4,575 $75.98
__________
(1) In addition to the volumes above, the Company has FY
2018 Midland-Cushing crude oil basis swaps on 6,000 Bbls/d at a
weighted average price differential of ($0.10) and FY 2018
LLS-Cushing crude oil basis swaps on 6,000 Bbls/d at a weighted
average price differential of $2.91.
CARRIZO OIL &
GAS, INC. COMMODITY DERIVATIVE CONTRACTS - AS OF FEBRUARY
23, 2018 (Unaudited) (Continued)
NATURAL GAS
LIQUIDS Volume Fixed Price (1)
Period Product Stream Type of Contract
(Bbls/d) ($/Bbl) Q1 2018 Ethane Fixed Price
Swaps 2,200 $12.01 Propane Fixed Price Swaps 1,500 $34.23 Butane
Fixed Price Swaps 200 $38.85 Isobutane Fixed Price Swaps 600 $38.98
Natural Gasoline Fixed Price Swaps 600 $55.23 Q2 2018 Ethane
Fixed Price Swaps 2,200 $12.01 Propane Fixed Price Swaps 1,500
$34.23 Butane Fixed Price Swaps 200 $38.85 Isobutane Fixed Price
Swaps 600 $38.98 Natural Gasoline Fixed Price Swaps 600 $55.23
Q3 2018 Ethane Fixed Price Swaps 2,200 $12.01 Propane Fixed
Price Swaps 1,500 $34.23 Butane Fixed Price Swaps 200 $38.85
Isobutane Fixed Price Swaps 600 $38.98 Natural Gasoline Fixed Price
Swaps 600 $55.23 Q4 2018 Ethane Fixed Price Swaps 2,200
$12.01 Propane Fixed Price Swaps 1,500 $34.23 Butane Fixed Price
Swaps 200 $38.85 Isobutane Fixed Price Swaps 600 $38.98 Natural
Gasoline Fixed Price Swaps 600 $55.23
_____________
(1) The fixed prices of the Company's
natural gas liquids derivative contracts are based on the OPIS Mont
Belvieu Non-TET reference prices for the applicable product
stream.
NATURAL GAS Volume Floor
Price Ceiling Price Period Type of
Contract (MMBtu/d) ($/MMBtu) ($/MMBtu) Q1
2018 Fixed Price Swaps 8,611 $3.01 Sold Call Options 33,000 $3.25
Q2 2018 Fixed Price Swaps 25,000 $3.01 Sold Call Options
33,000 $3.25 Q3 2018 Fixed Price Swaps 25,000 $3.01 Sold
Call Options 33,000 $3.25 Q4 2018 Fixed Price Swaps 25,000
$3.01 Sold Call Options 33,000 $3.25 FY 2019 Sold Call
Options 33,000 $3.25 FY 2020 Sold Call Options 33,000 $3.50
CARRIZO OIL & GAS, INC. FIRST QUARTER AND FULL
YEAR 2018 GUIDANCE SUMMARY
First Quarter 2018 Full Year 2018 Daily Production
Volumes (Boe/d) 48,600 - 49,800 58,500 - 60,100 Crude oil 65% -
67% 65% - 67% NGLs 15% - 17% 15% - 17% Natural gas 17% - 19% 17% -
19%
Unhedged Commodity Price Realizations Crude oil
(% of NYMEX oil) 99.0% - 101.0% N/A NGLs (% of NYMEX oil) 33.0% -
35.0% N/A Natural gas (% of NYMEX gas) 91.0% - 93.0% N/A
Cash paid for derivative settlements, net ($MM) ($16.0) - ($13.0)
N/A
Costs and Expenses - Lease operating ($/Boe)
$8.50 - $9.00 $7.50 - $8.25 Production taxes (% of total revenues)
4.75% - 5.00% 4.75% - 5.25% Ad valorem taxes ($MM) $2.3 - $2.8 $8.0
- $10.0 Cash general and administrative, net ($MM) $24.0 - $24.5
$52.5 - $54.5 Depreciation, depletion and amortization ($/Boe)
$13.75 - $14.75 $13.50 - $14.50 Interest expense, net ($MM) $15.8 -
$16.8 N/A
Capital Expenditures - Drilling,
completion, and infrastructure ($MM) N/A $750.0 - $800.0 Interest
($MM) $9.8 - $10.3 N/A
View source
version on businesswire.com: http://www.businesswire.com/news/home/20180226006492/en/
Carrizo Oil & Gas, Inc.Jeffrey P. Hayden,
CFAVP - Investor Relations(713) 328-1044orKim
PinyopusarerkManager - Investor Relations(713)
358-6430
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