Carrizo Oil & Gas Announces Fourth Quarter and Year-End 2018 Results HOUSTON
Carrizo Oil & Gas, Inc. (Nasdaq: CRZO) today announced the
Company’s financial results for the fourth quarter and year-end 2018 and
provided an operational update. Highlights include:
Fourth Quarter 2018 Highlights
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Total production of 68,328 Boe/d, 9% above the fourth quarter of 2017
and 6% above the third quarter of 2018
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Crude oil production of 43,040 Bbls/d, 7% above the fourth quarter of
2017 and 5% above the third quarter of 2018
-
Net income attributable to common shareholders of $255.1 million, or
$2.75 per diluted share, and Net cash provided by operating activities
of $188.3 million
-
Adjusted net income attributable to common shareholders of $52.1
million, or $0.56 per diluted share, and Adjusted EBITDA of $170.7
million
Year-end 2018 Highlights
-
Proved reserves of 329.4 MMBoe, a 26% increase over year-end 2017
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Standardized measure of discounted future net cash flows of $3.6
billion, and PV-10 of $4.1 billion, a 55% increase over year-end 2017
-
478% reserve replacement from all sources at a finding, development,
and acquisition (FD&A) cost of $10.34 per Boe
Guidance and Operational Highlights
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As previously announced, 2019 DC&I capital expenditure plan of
$525-$575 million, which is expected to deliver double-digit
production growth while achieving positive free cash flow by the third
quarter of the year
-
Achievement of cost reductions and efficiency gains that have driven
materially-lower well costs across the asset portfolio
-
Encouraging results from initial two Wolfcamp C tests in the Delaware
Basin
Carrizo reported fourth quarter of 2018 net income attributable to
common shareholders of $255.1 million, or $2.79 and $2.75 per basic and
diluted share, respectively, compared to a net loss attributable to
common shareholders of $23.4 million, or $0.29 per basic and diluted
share, in the fourth quarter of 2017. The net income attributable to
common shareholders for the fourth quarter of 2018 and the net loss
attributable to common shareholders for the fourth quarter of 2017
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 below, for the fourth quarter of 2018
was $52.1 million, or $0.56 per diluted share, compared to $47.9
million, or $0.58 per diluted share, in the fourth quarter of 2017.
For the fourth quarter of 2018, Adjusted EBITDA was $170.7 million.
Adjusted EBITDA and the reconciliation to net income (loss) attributable
to common shareholders and net cash provided by operating activities are
presented in the non-GAAP reconciliation tables below.
Production volumes during the fourth quarter of 2018 were 6,286 MBoe, or
68,328 Boe/d, an increase of 9% versus the fourth quarter of 2017. The
year-over-year growth was driven by the Delaware Basin, where the
Company’s production increased by approximately 96%. Crude oil
production during the fourth quarter of 2018 averaged 43,040 Bbls/d, an
increase of 7% versus the fourth quarter of 2017; natural gas and NGL
production were 83,067 Mcf/d and 11,443 Bbls/d, respectively, during the
fourth quarter of 2018. Fourth quarter of 2018 production was within the
Company’s guidance range of 67,700-68,700 Boe/d.
Drilling, completion, and infrastructure (DC&I) capital expenditures for
the fourth quarter of 2018 were $175.4 million. Approximately 78% of the
fourth quarter DC&I spending was in the Eagle Ford Shale, with the
balance in the Delaware Basin. Land and seismic capital expenditures
during the quarter were $4.0 million, and were primarily focused in the
Delaware Basin.
Carrizo’s 2019 DC&I capital expenditure plan is unchanged from the
recently-announced level of $525.0-$575.0 million. The Company currently
expects to allocate approximately 60% of the capital to the Eagle Ford
Shale, with the balance to the Delaware Basin. The 2019 plan implies a
material improvement in capital efficiency relative to 2018. This
results from a combination of service cost reductions, efficiency gains,
and changes to completion techniques that have already been implemented.
Combined, these factors have led to a material reduction in the
Company’s well costs in both the Eagle Ford Shale and Delaware Basin.
Carrizo is reiterating its 2019 production guidance of 66,800-67,800
Boe/d. Crude oil production is expected to account for approximately 63%
of the Company's production for the year, while total liquids are
expected to account for approximately 80%. This 2019 production guidance
range equates to annual growth of approximately 11% at the midpoint. For
the first quarter of the year, Carrizo expects production to be
61,100-62,100 Boe/d; crude oil is expected to account for 64% of
production, while total liquids are expected to account for 81%. While
the Company’s production is expected to decline sequentially in the
first quarter due to the limited number of wells it turned to sales
while drilling its multipad project wells in late 2018, the Company
expects to see a material increase in its production during the second
quarter as these wells come online.
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, “The fourth quarter capped off another strong operational year
for Carrizo, and helped set the stage for us to achieve our goal of
long-term growth within cash flow. Thanks to our team’s dedication and
focus on driving efficiency gains and cost reductions throughout our
operations, we have been able to announce a 2019 capital plan that
equates to an approximate 35% reduction in spending, yet still delivers
double-digit production growth versus 2018. Importantly, our 2019 plan
also provides us with a clear path to a free-cash-flow-positive
inflection point, which we currently expect to achieve in the third
quarter of the year, and should provide us with positive operational
momentum into 2020.
“Operationally, one of our key corporate initiatives has been increasing
capital efficiency through the optimization of all phases of our
drilling and completion programs. This includes a wide range of
modifications to our Eagle Ford Shale completion design and well
spacing, as well as a shift to larger-scale development projects in both
the Eagle Ford Shale and Delaware Basin. These changes should drive
improved project-level economics, and thus, improved corporate returns.
In the Eagle Ford Shale, our recent activity has been focused on two
large-scale multipad projects, comprising 36 wells. One of the multipad
projects recently began production, while the other is expected to begin
next quarter; these two projects should drive significant production
growth during the year. In the Delaware Basin, we are currently
completing what we believe to be the first six-well, four-layer
co-development test of the Wolfcamp A, B, and C. Results from this
project will provide us with significant information that will be used
to optimize the future development of our acreage.
“In late 2018, we began testing additional targets within our pay stack
in the Delaware Basin. In the Phantom area, we have completed two
Wolfcamp C wells, with very encouraging results. In the Ford West area,
we have begun testing the Wolfcamp B, with our initial well being part
of a multi-layer co-development test. We are also quite pleased with the
early results from this well. To date, we have not included any credit
for the Wolfcamp B in the Ford West area or the Wolfcamp C in the
Phantom area in our estimate of de-risked drilling inventory.
“During 2018, we continued to build upon our track record of strong
reserve growth. For the year, our proved reserves increased by 26% to
329 MMBoe. This was driven by an increase of 98% in the Delaware Basin,
which currently accounts for 55% of our proved reserves. Our reserve
growth has also led to a material increase in our PV-10, which is
currently estimated at $4.1 billion, up 55% versus year-end 2017.”
2018 Proved Reserves
The Company’s proved reserves as of December 31, 2018 were 329.4 MMBoe,
including crude oil reserves of 179.7 MMBbls. The Company’s PV-10 was
$4.1 billion as of December 31, 2018. PV-10 and the reconciliation to
the standardized measure of discounted future net cash flows are
presented in the non-GAAP reconciliation tables below.
The table below summarizes the Company’s year-end 2018 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, 2018 based on the West Texas Intermediate benchmark
crude oil price of $65.56/Bbl and the Henry Hub benchmark natural gas
price of $3.10/MMBtu, before adjustment for differentials.
|
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Crude Oil
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NGLs
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Natural Gas
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Total
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PV-10
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Region
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(MMBbl)
|
|
|
(MMBbl)
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|
|
(Bcf)
|
|
|
(MMBoe)
|
|
|
($MM)
|
Eagle Ford Shale
|
|
|
110.9
|
|
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19.2
|
|
|
114.1
|
|
|
149.1
|
|
|
$
|
2,691.8
|
Delaware Basin
|
|
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68.8
|
|
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49.9
|
|
|
369.0
|
|
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180.3
|
|
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1,399.6
|
Total
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|
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179.7
|
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69.1
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483.1
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329.4
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$
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4,091.4
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The table below summarizes the changes in the Company’s proved reserves
during 2018.
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Crude Oil
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NGLs
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Natural Gas
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Total
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(MMBbl)
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(MMBbl)
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(Bcf)
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(MMBoe)
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Proved reserves - December 31, 2017
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167.4
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|
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42.6
|
|
|
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310.5
|
|
|
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261.7
|
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Extensions and discoveries
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65.3
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|
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30.2
|
|
|
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212.8
|
|
|
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131.0
|
|
Removed due to changes in development plan
|
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(16.2
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)
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(2.8
|
)
|
|
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(16.8
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)
|
|
|
(21.8
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)
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Revisions of previous estimates
|
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(15.1
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)
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4.7
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10.8
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|
|
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(8.5
|
)
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Purchases of reserves in place
|
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2.2
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|
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1.0
|
|
|
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7.9
|
|
|
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4.5
|
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Divestitures of reserves in place
|
|
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(9.7
|
)
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(2.9
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)
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(17.5
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)
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|
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(15.5
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)
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Production
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(14.2
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)
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|
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(3.7
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)
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|
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(24.6
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)
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|
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(22.0
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)
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Proved reserves - December 31, 2018
|
|
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179.7
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|
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69.1
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|
|
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483.1
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|
|
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329.4
|
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Proved developed - December 31, 2018
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|
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75.3
|
|
|
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25.8
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|
|
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178.9
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|
|
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130.9
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|
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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, 2018.
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Total
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($MM)
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Property acquisition costs
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|
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Proved properties
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|
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$47.4
|
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Unproved properties
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|
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182.2
|
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Total property acquisition costs
|
|
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229.6
|
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Exploration costs
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|
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48.6
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Development costs
|
|
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809.6
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Total costs incurred (1)
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$1,087.8
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__________
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(1)
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Total costs incurred includes capitalized general and administrative
expense and asset retirement obligations and excludes capitalized
interest.
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2018 highlights include:
-
Total reserve replacement was 478% at an all-sources FD&A cost of
$10.34 per Boe
-
Drill-bit reserve replacement was 458% at a drill-bit F&D cost of
$8.52 per Boe
-
Total proved reserves increased to 329.4 MMBoe, a 26% increase versus
year-end 2017
-
Delaware Basin reserves increased to 180.3 MMBoe, a 98% increase
versus year-end 2017
-
Proved developed reserves increased to 130.9 MMBoe, a 20% increase
versus year-end 2017
-
PV-10 increased to $4.1 billion, a 55% increase versus year-end 2017
-
Crude oil represents 55% of total proved reserves and 79% of PV-10 at
December 31, 2018
Operational Update
In the Eagle Ford Shale, where the Company holds approximately 76,500
net acres, Carrizo drilled 38 gross (37 net) operated wells during the
fourth quarter and completed 18 gross (16 net) operated wells.
Production was approximately 38,600 Boe/d for the quarter, roughly flat
with the prior quarter. Crude oil production during the fourth quarter
was more than 30,600 Bbls/d, an increase of 2% versus the prior quarter;
crude oil accounted for 79% of the Company’s production from the play.
At the end of the quarter, Carrizo had 39 gross (39 net) operated Eagle
Ford Shale wells waiting on completion. Carrizo currently expects to
drill 50-55 gross (45-50 net) operated wells and complete 75-80 gross
(70-75 net) operated wells in the play during 2019.
As the Company seeks to maximize capital efficiency and generate free
cash flow in a mid-$50’s crude oil price environment, it has implemented
a wide range of operational and strategic changes to its Eagle Ford
Shale development plan. The operational modifications are primarily
focused on completion design, and include discontinuing the use of
diverter, optimizing sand concentration and frac stage length, utilizing
locally-sourced frac sand, and returning to a hybrid frac design. As a
result, Carrizo has recently been able to improve its completion pace to
more than 9 stages per day versus 6-7 stages per day on average in 2018.
Strategically, the Company believes that multipad development is the
most profitable way to develop its remaining locations in the play, and
plans to utilize this technique on the balance of its inventory. While
the Company expects the impact of the completion changes combined with
multipad development to be neutral to per-well EURs on a go-forward
basis, the changes have helped reduce well costs by approximately 5% to
$4.3 million for a 6,600-ft. lateral well and significantly reduced the
impact of completions on offsetting parent wells. As a result, these
changes should have a positive impact on Carrizo’s field-wide
profitability and corporate-level returns.
Carrizo has also benefited from operational process improvements in the
play. This, combined with refinements to data tracking and analysis, has
allowed the Company to compress cycle times within development projects
as lessons learned are transferred more quickly to the next well. During
the fourth quarter, the Company drilled two of its longest laterals to
date in the Eagle Ford Shale. With an average effective lateral of
approximately 13,600 feet, these wells were drilled an average of four
to six days faster than its prior longest well; and this was achieved
despite the new wells having a 5%-10% longer lateral than the prior
record well.
Based on the performance from its initial multipad project in the play,
Carrizo began development of two additional multipad projects in the
second half of 2018; a 15-well project in the Pena area and a 21-well
project in the RPG area. The Pena project wells were completed in the
middle of the first quarter and recently began flowback. Completion of
the RPG project wells is underway and the wells are expected to begin
coming online during the second quarter. These two projects should drive
significant production growth during 2019.
In the Delaware Basin, where it holds more than 46,000 net acres,
Carrizo drilled 5 gross (4 net) operated wells during the fourth
quarter. Production was approximately 29,700 Boe/d for the quarter, up
16% versus the prior quarter. Crude oil production during the fourth
quarter was approximately 12,400 Bbls/d, accounting for 42% of the
Company’s production from the play. At the end of the quarter, Carrizo
had 11 gross (9 net) operated Delaware Basin wells waiting on
completion. Carrizo currently expects to drill 25-30 gross (20-25 net)
operated wells and complete 20-25 gross (15-20 net) operated wells in
the play during 2019.
Carrizo’s primary operational focus in the Delaware Basin during the
first half of 2019 is testing multi-layer, co-development concepts in
the Phantom area. The Company is currently completing the area’s first
large-scale co-development test of the Wolfcamp A, B, and C, which
consists of six wells testing four landing zones coupled with an
extensive microseismic and production-tracer monitoring program. The
frac sequencing for the program is designed to help assess created frac
height, length, and barriers, as well as the impact of offset-frac
stress shadowing for various configurations. This project, along with
ongoing field study efforts, will help Carrizo evaluate potential
improvements from co-development as well as optimize completion design,
well spacing, and landing zone selection within each Wolfcamp layer.
During late 2018, Carrizo began its evaluation of the Wolfcamp C on its
Phantom acreage. To date, the Company has drilled four Wolfcamp C wells
and completed two in the area; initial production results have been very
encouraging. The Woodson 36 Allocation B 20H began production during the
fourth quarter and recently recorded a peak 90-day rate of more than
1,500 Boe/d (45% oil, 73% liquids) from a lateral of approximately 9,800
ft. The Company’s second Wolfcamp C well, the Zeman 40 Allocation F 42H,
came online at the end of January and has thus far achieved a peak
24-hour rate in excess of 1,900 Boe/d (60% oil, 80% liquids) from a
lateral of 7,750 ft.
In the Ford West area, Carrizo drilled and completed its initial
multi-layer, co-development test during 2018. The three-well Liberator
pad tested a staggered co-development of the Wolfcamp A and B, with the
outside wells targeting the A and the middle well targeting the B;
production began late last year. The Liberator State Unit 21H, which
targeted the Wolfcamp B, recorded a peak 60-day rate of approximately
2,100 Boe/d (32% oil, 67% liquids) from a lateral of 11,850 ft., while
the Liberator State Unit 20H and 22H, which both targeted the Wolfcamp
A, recorded average peak 60-day rates of approximately 1,400 Boe/d (43%
oil, 72% liquids) from an average lateral of approximately 8,100 ft. The
Company has additional co-development tests planned for 2019 and expects
to provide updates on these once it has sufficient production history.
Consistent with its goal of maximizing returns, Carrizo remains focused
on driving down costs in its Delaware Basin operations. As it has in
every other resource play in which it has operated, the Company has been
able to achieve significant drilling efficiencies in its first 18 months
of operations. Reduction in drilling days, logistical improvements,
procurement of locally-sourced frac sand, and design optimizations have
combined to yield a 10%-15% reduction in drilling cost per foot and
completion cost per stage. As a result of these efforts, Carrizo has
reduced its projected Delaware Basin well cost by approximately $1.0
million to approximately $8.5 million for a 7,000-ft. lateral.
Hedging Activity
Hedging continues to be an important element of Carrizo’s strategy to
protect its balance sheet and provide predictable cash flows. As part of
this strategy, the Company maintains an active hedging program while
retaining the flexibility to benefit from commodity price increases.
Carrizo currently has hedges in place for over 60% of estimated crude
oil production for 2019 (based on the midpoint of guidance). For the
year, the Company has three-way collars covering 27,000 Bbls/d of crude
oil with an average floor price of $50.96/Bbl, ceiling price of
$74.23/Bbl, and sub-floor price of $41.67/Bbl.
Carrizo recently began to add 2020 crude oil hedges to its portfolio.
For 2020, the Company currently has swaps covering 3,000 Bbls/d of crude
oil at an average fixed price of $55.06/Bbl and three-way collars
covering 6,000 Bbls/d with an average floor price of $55.00/Bbl, ceiling
price of $64.69/Bbl, and sub-floor price of $45.00/Bbl.
Please refer to the attached tables for full details of the Company’s
commodity derivative contracts.
Conference Call Details
The Company will hold a conference call to discuss fourth quarter and
year-end 2018 financial results on Tuesday, February 26, 2019 at 10:00
AM Central Standard Time. To participate in the call, please dial (800)
698-0460 (U.S. & Canada) or +1 (303) 223-4374 (Intl.) ten minutes before
the call is scheduled to begin. A replay of the call will be available
through Tuesday, March 5, 2019 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 21915115 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 “2018 Fourth Quarter
and Year-end Conference Call Webcast”. 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.
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, expectations
or projections, cost reductions, drilling, fracking and capital
efficiencies, cycle times, growth within cash flow and timing of free
cash flow generation, activity among basins, goals, leverage metrics,
capital expenditure, infrastructure program, resource potential,
guidance, results of tests, rig program, production, average well
returns, estimated production results and financial performance, effects
of transactions, targeted ratios and other metrics, timing, levels of
and potential production, expectations regarding growth, oil and gas
prices, drilling and completion activities and optimization, benefits of
certain well completion designs, well spacing, landing zone
optimization, drilling techniques, including multi-pad and multi-zone
drilling, completion and development techniques, drilling inventory,
including timing thereof, well costs, break-even prices, production mix,
development plans, 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, Delaware Basin constraints, estimated
recoveries, pricing and other factors affecting average well returns,
results of wells and testing, failure of actual production to meet
expectations, results of infrastructure program, failure to reach
significant growth, performance of rig operators, spacing test results,
availability of gathering systems, pipeline and other transportation
issues, costs and availability of oilfield services, actions by
governmental authorities, joint venture partners, industry partners,
lenders and other third parties, actions by purchasers or sellers of
properties, 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, 2017 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,
|
|
|
|
2018
|
|
|
2017
|
Assets
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
$2,282
|
|
|
|
$9,540
|
|
Accounts receivable, net
|
|
|
99,723
|
|
|
|
107,441
|
|
Derivative assets
|
|
|
39,904
|
|
|
|
—
|
|
Other current assets
|
|
|
8,460
|
|
|
|
5,897
|
|
Total current assets
|
|
|
150,369
|
|
|
|
122,878
|
|
Property and equipment
|
|
|
|
|
|
|
Oil and gas properties, full cost method
|
|
|
|
|
|
|
Proved properties, net
|
|
|
2,333,470
|
|
|
|
1,965,347
|
|
Unproved properties, not being amortized
|
|
|
673,833
|
|
|
|
660,287
|
|
Other property and equipment, net
|
|
|
11,221
|
|
|
|
10,176
|
|
Total property and equipment, net
|
|
|
3,018,524
|
|
|
|
2,635,810
|
|
Other long-term assets
|
|
|
16,207
|
|
|
|
19,616
|
|
Total Assets
|
|
|
$3,185,100
|
|
|
|
$2,778,304
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
Accounts payable
|
|
|
$98,811
|
|
|
|
$74,558
|
|
Revenues and royalties payable
|
|
|
49,003
|
|
|
|
52,154
|
|
Accrued capital expenditures
|
|
|
60,004
|
|
|
|
119,452
|
|
Accrued interest
|
|
|
18,377
|
|
|
|
28,362
|
|
Derivative liabilities
|
|
|
55,205
|
|
|
|
57,121
|
|
Other current liabilities
|
|
|
40,609
|
|
|
|
41,175
|
|
Total current liabilities
|
|
|
322,009
|
|
|
|
372,822
|
|
Long-term debt
|
|
|
1,633,591
|
|
|
|
1,629,209
|
|
Asset retirement obligations
|
|
|
18,360
|
|
|
|
23,497
|
|
Derivative liabilities
|
|
|
40,817
|
|
|
|
112,332
|
|
Deferred income taxes
|
|
|
8,017
|
|
|
|
3,635
|
|
Other long-term liabilities
|
|
|
6,980
|
|
|
|
51,650
|
|
Total liabilities
|
|
|
2,029,774
|
|
|
|
2,193,145
|
|
Commitments and contingencies
|
|
|
|
|
|
|
Preferred stock
|
|
|
|
|
|
|
Preferred stock, $0.01 par value, 10,000,000 shares authorized;
200,000 issued and outstanding as of December 31, 2018 and 250,000
issued and outstanding as of December 31, 2017
|
|
|
174,422
|
|
|
|
214,262
|
|
Shareholders’ equity
|
|
|
|
|
|
|
Common stock, $0.01 par value, 180,000,000 shares authorized;
91,627,738 issued and outstanding as of December 31, 2018 and
81,454,621 issued and outstanding as of December 31, 2017
|
|
|
916
|
|
|
|
815
|
|
Additional paid-in capital
|
|
|
2,131,535
|
|
|
|
1,926,056
|
|
Accumulated deficit
|
|
|
(1,151,547
|
)
|
|
|
(1,555,974
|
)
|
Total shareholders’ equity
|
|
|
980,904
|
|
|
|
370,897
|
|
Total Liabilities and Shareholders’ Equity
|
|
|
$3,185,100
|
|
|
|
$2,778,304
|
|
|
|
|
|
|
|
|
|
|
|
CARRIZO OIL & GAS, INC.
|
CONSOLIDATED STATEMENTS OF OPERATIONS
|
(In thousands, except per share amounts)
|
(Unaudited)
|
|
|
|
|
Three Months Ended December 31,
|
|
|
Years Ended December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
$232,312
|
|
|
|
$210,234
|
|
|
|
$911,554
|
|
|
|
$633,233
|
|
Natural gas liquids
|
|
|
24,616
|
|
|
|
19,727
|
|
|
|
96,585
|
|
|
|
47,405
|
|
Natural gas
|
|
|
16,386
|
|
|
|
16,810
|
|
|
|
57,803
|
|
|
|
65,250
|
|
Total revenues
|
|
|
273,314
|
|
|
|
246,771
|
|
|
|
1,065,942
|
|
|
|
745,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
46,150
|
|
|
|
39,087
|
|
|
|
161,596
|
|
|
|
139,854
|
|
Production taxes
|
|
|
13,013
|
|
|
|
11,417
|
|
|
|
50,591
|
|
|
|
32,509
|
|
Ad valorem taxes
|
|
|
2,221
|
|
|
|
1,491
|
|
|
|
10,422
|
|
|
|
7,267
|
|
Depreciation, depletion and amortization
|
|
|
82,525
|
|
|
|
81,571
|
|
|
|
299,530
|
|
|
|
262,589
|
|
General and administrative, net
|
|
|
10,249
|
|
|
|
16,901
|
|
|
|
68,617
|
|
|
|
66,229
|
|
(Gain) loss on derivatives, net
|
|
|
(159,407
|
)
|
|
|
86,107
|
|
|
|
(6,709
|
)
|
|
|
59,103
|
|
Interest expense, net
|
|
|
15,891
|
|
|
|
18,520
|
|
|
|
62,413
|
|
|
|
80,870
|
|
Loss on extinguishment of debt
|
|
|
910
|
|
|
|
4,170
|
|
|
|
9,586
|
|
|
|
4,170
|
|
Other (income) expense, net
|
|
|
(2,009
|
)
|
|
|
517
|
|
|
|
296
|
|
|
|
2,157
|
|
Total costs and expenses
|
|
|
9,543
|
|
|
|
259,781
|
|
|
|
656,342
|
|
|
|
654,748
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
|
|
263,771
|
|
|
|
(13,010
|
)
|
|
|
409,600
|
|
|
|
91,140
|
|
Income tax expense
|
|
|
(3,491
|
)
|
|
|
(4,030
|
)
|
|
|
(5,173
|
)
|
|
|
(4,030
|
)
|
Net Income (Loss)
|
|
|
$260,280
|
|
|
|
($17,040
|
)
|
|
|
$404,427
|
|
|
|
$87,110
|
|
Dividends on preferred stock
|
|
|
(4,367
|
)
|
|
|
(5,532
|
)
|
|
|
(18,161
|
)
|
|
|
(7,781
|
)
|
Accretion on preferred stock
|
|
|
(793
|
)
|
|
|
(862
|
)
|
|
|
(3,057
|
)
|
|
|
(862
|
)
|
Loss on redemption of preferred stock
|
|
|
—
|
|
|
|
—
|
|
|
|
(7,133
|
)
|
|
|
—
|
|
Net Income (Loss) Attributable to Common Shareholders
|
|
|
$255,120
|
|
|
|
($23,434
|
)
|
|
|
$376,076
|
|
|
|
$78,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Common Shareholders Per
Common Share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
$2.79
|
|
|
|
($0.29
|
)
|
|
|
$4.40
|
|
|
|
$1.07
|
|
Diluted
|
|
|
$2.75
|
|
|
|
($0.29
|
)
|
|
|
$4.32
|
|
|
|
$1.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
91,586
|
|
|
|
81,415
|
|
|
|
85,509
|
|
|
|
73,421
|
|
Diluted
|
|
|
92,821
|
|
|
|
81,415
|
|
|
|
87,143
|
|
|
|
73,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CARRIZO OIL & GAS, INC.
|
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
|
(In thousands, except share amounts)
|
(Unaudited)
|
|
|
|
|
Common Stock
|
|
|
Additional Paid-in Capital
|
|
|
Accumulated Deficit
|
|
|
Total Shareholders’ Equity
|
|
|
|
Shares
|
|
|
Amount
|
|
|
|
|
|
|
Balance as of December 31, 2017
|
|
|
81,454,621
|
|
|
|
$815
|
|
|
|
$1,926,056
|
|
|
|
($1,555,974
|
)
|
|
|
$370,897
|
|
Stock-based compensation expense
|
|
|
—
|
|
|
|
—
|
|
|
|
20,412
|
|
|
|
—
|
|
|
|
20,412
|
|
Issuance of common stock upon grants of restricted stock awards and
vestings of restricted stock units and performance shares, net of
forfeitures
|
|
|
673,117
|
|
|
|
6
|
|
|
|
(233
|
)
|
|
|
—
|
|
|
|
(227
|
)
|
Sale of common stock, net of offering costs
|
|
|
9,500,000
|
|
|
|
95
|
|
|
|
213,651
|
|
|
|
—
|
|
|
|
213,746
|
|
Dividends on preferred stock
|
|
|
—
|
|
|
|
—
|
|
|
|
(18,161
|
)
|
|
|
—
|
|
|
|
(18,161
|
)
|
Accretion on preferred stock
|
|
|
—
|
|
|
|
—
|
|
|
|
(3,057
|
)
|
|
|
—
|
|
|
|
(3,057
|
)
|
Loss on redemption of preferred stock
|
|
|
—
|
|
|
|
—
|
|
|
|
(7,133
|
)
|
|
|
—
|
|
|
|
(7,133
|
)
|
Net income
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
404,427
|
|
|
|
404,427
|
|
Balance as of December 31, 2018
|
|
|
91,627,738
|
|
|
|
$916
|
|
|
|
$2,131,535
|
|
|
|
($1,151,547
|
)
|
|
|
$980,904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CARRIZO OIL & GAS, INC.
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
(In thousands)
|
(Unaudited)
|
|
|
|
|
Three Months Ended December 31,
|
|
|
Years Ended December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$260,280
|
|
|
|
($17,040
|
)
|
|
|
$404,427
|
|
|
|
$87,110
|
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
82,525
|
|
|
|
81,571
|
|
|
|
299,530
|
|
|
|
262,589
|
|
(Gain) loss on derivatives, net
|
|
|
(159,407
|
)
|
|
|
86,107
|
|
|
|
(6,709
|
)
|
|
|
59,103
|
|
Cash received (paid) for derivative settlements, net
|
|
|
(31,597
|
)
|
|
|
59
|
|
|
|
(96,307
|
)
|
|
|
7,773
|
|
Loss on extinguishment of debt
|
|
|
910
|
|
|
|
4,170
|
|
|
|
9,586
|
|
|
|
4,170
|
|
Stock-based compensation expense, net
|
|
|
(262
|
)
|
|
|
5,847
|
|
|
|
13,524
|
|
|
|
14,309
|
|
Deferred income tax expense
|
|
|
3,318
|
|
|
|
3,635
|
|
|
|
4,381
|
|
|
|
3,635
|
|
Non-cash interest expense, net
|
|
|
689
|
|
|
|
696
|
|
|
|
2,567
|
|
|
|
3,657
|
|
Other, net
|
|
|
116
|
|
|
|
(1,912
|
)
|
|
|
4,216
|
|
|
|
2,337
|
|
Changes in components of working capital and other assets and
liabilities-
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
36,771
|
|
|
|
(15,745
|
)
|
|
|
24,008
|
|
|
|
(41,630
|
)
|
Accounts payable
|
|
|
5,150
|
|
|
|
(2,926
|
)
|
|
|
16,013
|
|
|
|
11,822
|
|
Accrued liabilities
|
|
|
(9,818
|
)
|
|
|
(458
|
)
|
|
|
(19,154
|
)
|
|
|
11,512
|
|
Other assets and liabilities, net
|
|
|
(412
|
)
|
|
|
(1,620
|
)
|
|
|
(2,527
|
)
|
|
|
(3,406
|
)
|
Net cash provided by operating activities
|
|
|
188,263
|
|
|
|
142,384
|
|
|
|
653,555
|
|
|
|
422,981
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(306,369
|
)
|
|
|
(221,150
|
)
|
|
|
(968,828
|
)
|
|
|
(654,711
|
)
|
Acquisitions of oil and gas properties
|
|
|
(183,354
|
)
|
|
|
(3,768
|
)
|
|
|
(204,854
|
)
|
|
|
(695,774
|
)
|
Proceeds from divestitures of oil and gas properties
|
|
|
3,741
|
|
|
|
173,152
|
|
|
|
381,434
|
|
|
|
197,564
|
|
Other, net
|
|
|
(1,033
|
)
|
|
|
(2,727
|
)
|
|
|
(3,720
|
)
|
|
|
(6,531
|
)
|
Net cash used in investing activities
|
|
|
(487,015
|
)
|
|
|
(54,493
|
)
|
|
|
(795,968
|
)
|
|
|
(1,159,452
|
)
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of senior notes, net of issuance costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
245,418
|
|
Redemptions of senior notes and other long-term debt
|
|
|
(130,105
|
)
|
|
|
(152,813
|
)
|
|
|
(460,540
|
)
|
|
|
(152,813
|
)
|
Redemption of preferred stock
|
|
|
—
|
|
|
|
—
|
|
|
|
(50,030
|
)
|
|
|
—
|
|
Borrowings under credit agreement
|
|
|
894,192
|
|
|
|
680,648
|
|
|
|
3,309,400
|
|
|
|
1,992,523
|
|
Repayments of borrowings under credit agreement
|
|
|
(459,598
|
)
|
|
|
(604,948
|
)
|
|
|
(2,856,269
|
)
|
|
|
(1,788,223
|
)
|
Payments of credit facility amendment fees
|
|
|
(1,047
|
)
|
|
|
(87
|
)
|
|
|
(1,674
|
)
|
|
|
(4,469
|
)
|
Sale of common stock, net of offering costs
|
|
|
(111
|
)
|
|
|
—
|
|
|
|
213,746
|
|
|
|
222,378
|
|
Sale of preferred stock, net of issuance costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
236,404
|
|
Payments of dividends on preferred stock
|
|
|
(4,366
|
)
|
|
|
(5,532
|
)
|
|
|
(18,161
|
)
|
|
|
(7,781
|
)
|
Other, net
|
|
|
(346
|
)
|
|
|
(711
|
)
|
|
|
(1,317
|
)
|
|
|
(1,620
|
)
|
Net cash provided by (used in) financing activities
|
|
|
298,619
|
|
|
|
(83,443
|
)
|
|
|
135,155
|
|
|
|
741,817
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(133
|
)
|
|
|
4,448
|
|
|
|
(7,258
|
)
|
|
|
5,346
|
|
Cash and Cash Equivalents, Beginning of Period
|
|
|
2,415
|
|
|
|
5,092
|
|
|
|
9,540
|
|
|
|
4,194
|
|
Cash and Cash Equivalents, End of Period
|
|
|
$2,282
|
|
|
|
$9,540
|
|
|
|
$2,282
|
|
|
|
$9,540
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Ended December 31,
|
|
|
|
Years Ended December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
2018
|
|
|
2017
|
|
|
|
(In thousands, except per share amounts)
|
Net Income (Loss) Attributable to Common Shareholders (GAAP)
|
|
|
$255,120
|
|
|
|
($23,434
|
)
|
|
|
|
$376,076
|
|
|
|
$78,467
|
|
Loss on redemption of preferred stock
|
|
|
—
|
|
|
|
—
|
|
|
|
|
7,133
|
|
|
|
—
|
|
Income tax expense
|
|
|
3,491
|
|
|
|
4,030
|
|
|
|
|
5,173
|
|
|
|
4,030
|
|
(Gain) loss on derivatives, net
|
|
|
(159,407
|
)
|
|
|
86,107
|
|
|
|
|
(6,709
|
)
|
|
|
59,103
|
|
Cash received (paid) for derivative settlements, net
|
|
|
(31,597
|
)
|
|
|
59
|
|
|
|
|
(96,307
|
)
|
|
|
7,773
|
|
Non-cash general and administrative, net
|
|
|
(262
|
)
|
|
|
6,194
|
|
|
|
|
13,645
|
|
|
|
15,284
|
|
Loss on extinguishment of debt
|
|
|
910
|
|
|
|
4,170
|
|
|
|
|
9,586
|
|
|
|
4,170
|
|
Non-recurring and other (income) expense, net
|
|
|
(1,163
|
)
|
|
|
517
|
|
|
|
|
3,203
|
|
|
|
2,157
|
|
Adjusted income before income taxes
|
|
|
67,092
|
|
|
|
77,643
|
|
|
|
|
311,800
|
|
|
|
170,984
|
|
Adjusted income tax expense (1)
|
|
|
(14,962
|
)
|
|
|
(29,737
|
)
|
|
|
|
(69,531
|
)
|
|
|
(65,487
|
)
|
Adjusted Net Income Attributable to Common Shareholders (Non-GAAP)
|
|
|
$52,130
|
|
|
|
$47,906
|
|
|
|
|
$242,269
|
|
|
|
$105,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Common Shareholders Per
Diluted Common Share (GAAP)
|
|
|
$2.75
|
|
|
|
($0.29
|
)
|
|
|
|
$4.32
|
|
|
|
$1.06
|
|
Loss on redemption of preferred stock
|
|
|
—
|
|
|
|
—
|
|
|
|
|
0.08
|
|
|
|
—
|
|
Income tax expense
|
|
|
0.03
|
|
|
|
0.05
|
|
|
|
|
0.06
|
|
|
|
0.05
|
|
(Gain) loss on derivatives, net
|
|
|
(1.72
|
)
|
|
|
1.05
|
|
|
|
|
(0.08
|
)
|
|
|
0.80
|
|
Cash received (paid) for derivative settlements, net
|
|
|
(0.34
|
)
|
|
|
—
|
|
|
|
|
(1.11
|
)
|
|
|
0.11
|
|
Non-cash general and administrative, net
|
|
|
—
|
|
|
|
0.08
|
|
|
|
|
0.16
|
|
|
|
0.21
|
|
Loss on extinguishment of debt
|
|
|
0.01
|
|
|
|
0.05
|
|
|
|
|
0.11
|
|
|
|
0.06
|
|
Non-recurring and other (income) expense, net
|
|
|
(0.01
|
)
|
|
|
0.01
|
|
|
|
|
0.04
|
|
|
|
0.02
|
|
Adjusted income before income taxes
|
|
|
0.72
|
|
|
|
0.95
|
|
|
|
|
3.58
|
|
|
|
2.31
|
|
Adjusted income tax expense
|
|
|
(0.16
|
)
|
|
|
(0.37
|
)
|
|
|
|
(0.80
|
)
|
|
|
(0.88
|
)
|
Adjusted Net Income Attributable to Common Shareholders Per
Diluted Common Share (Non-GAAP)
|
|
|
$0.56
|
|
|
|
$0.58
|
|
|
|
|
$2.78
|
|
|
|
$1.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted WASO (GAAP)
|
|
|
92,821
|
|
|
|
81,415
|
|
|
|
|
87,143
|
|
|
|
73,993
|
|
Dilutive shares adjustment
|
|
|
—
|
|
|
|
656
|
|
|
|
|
—
|
|
|
|
—
|
|
Adjusted Diluted WASO (Non-GAAP)
|
|
|
92,821
|
|
|
|
82,071
|
|
|
(2)
|
|
87,143
|
|
|
|
73,993
|
|
__________
|
(1)
|
|
|
For the three months and year ended December 31, 2018, adjusted
income tax expense was calculated using a rate of 22.3%, which
approximates the Company’s statutory tax rate adjusted for ordinary
permanent differences. For the three months and year ended December
31, 2017, adjusted income tax expense was calculated using a rate of
38.3%, which approximates the Company’s then statutory tax rate
adjusted for ordinary permanent differences.
|
(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 Ended December 31,
|
|
|
Years Ended December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
|
|
|
(In thousands, except per Boe amounts)
|
Net Income (Loss) Attributable to Common Shareholders (GAAP)
|
|
|
$255,120
|
|
|
|
($23,434
|
)
|
|
|
$376,076
|
|
|
|
$78,467
|
|
Dividends on preferred stock
|
|
|
4,367
|
|
|
|
5,532
|
|
|
|
18,161
|
|
|
|
7,781
|
|
Accretion on preferred stock
|
|
|
793
|
|
|
|
862
|
|
|
|
3,057
|
|
|
|
862
|
|
Loss on redemption of preferred stock
|
|
|
—
|
|
|
|
—
|
|
|
|
7,133
|
|
|
|
—
|
|
Income tax expense
|
|
|
3,491
|
|
|
|
4,030
|
|
|
|
5,173
|
|
|
|
4,030
|
|
Depreciation, depletion and amortization
|
|
|
82,525
|
|
|
|
81,571
|
|
|
|
299,530
|
|
|
|
262,589
|
|
Interest expense, net
|
|
|
15,891
|
|
|
|
18,520
|
|
|
|
62,413
|
|
|
|
80,870
|
|
(Gain) loss on derivatives, net
|
|
|
(159,407
|
)
|
|
|
86,107
|
|
|
|
(6,709
|
)
|
|
|
59,103
|
|
Cash received (paid) for derivative settlements, net
|
|
|
(31,597
|
)
|
|
|
59
|
|
|
|
(96,307
|
)
|
|
|
7,773
|
|
Non-cash general and administrative, net
|
|
|
(262
|
)
|
|
|
6,194
|
|
|
|
13,645
|
|
|
|
15,284
|
|
Loss on extinguishment of debt
|
|
|
910
|
|
|
|
4,170
|
|
|
|
9,586
|
|
|
|
4,170
|
|
Non-recurring and other (income) expense, net
|
|
|
(1,163
|
)
|
|
|
517
|
|
|
|
3,203
|
|
|
|
2,157
|
|
Adjusted EBITDA (Non-GAAP)
|
|
|
$170,668
|
|
|
|
$184,128
|
|
|
|
$694,961
|
|
|
|
$523,086
|
|
Cash interest expense, net
|
|
|
(15,202
|
)
|
|
|
(17,824
|
)
|
|
|
(59,846
|
)
|
|
|
(77,213
|
)
|
Dividends on preferred stock
|
|
|
(4,367
|
)
|
|
|
(5,532
|
)
|
|
|
(18,161
|
)
|
|
|
(7,781
|
)
|
Other cash and non-cash adjustments, net
|
|
|
1,146
|
|
|
|
(3,171
|
)
|
|
|
2,068
|
|
|
|
(1,190
|
)
|
Discretionary Cash Flows (Non-GAAP)
|
|
|
$152,245
|
|
|
|
$157,601
|
|
|
|
$619,022
|
|
|
|
$436,902
|
|
Changes in components of working capital and other
|
|
|
36,018
|
|
|
|
(15,217
|
)
|
|
|
34,533
|
|
|
|
(13,921
|
)
|
Net Cash Provided By Operating Activities (GAAP)
|
|
|
$188,263
|
|
|
|
$142,384
|
|
|
|
$653,555
|
|
|
|
$422,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (Non-GAAP)
|
|
|
$170,668
|
|
|
|
$184,128
|
|
|
|
$694,961
|
|
|
|
$523,086
|
|
Total barrels of oil equivalent
|
|
|
6,286
|
|
|
|
5,742
|
|
|
|
22,040
|
|
|
|
19,639
|
|
Adjusted EBITDA Margin ($ per Boe) (Non-GAAP)
|
|
|
$27.15
|
|
|
|
$32.07
|
|
|
|
$31.53
|
|
|
|
$26.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
(In millions)
|
Standardized measure of discounted future net cash flows (GAAP)
|
|
|
$3,635.6
|
|
|
$2,465.1
|
Add: present value of future income taxes discounted at 10% per annum
|
|
|
455.8
|
|
|
173.3
|
PV-10 (Non-GAAP)
|
|
|
$4,091.4
|
|
|
$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 Ended December 31,
|
|
|
Years Ended December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
Total production volumes -
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (MBbls)
|
|
|
3,960
|
|
|
3,699
|
|
|
14,232
|
|
|
12,566
|
NGLs (MBbls)
|
|
|
1,053
|
|
|
845
|
|
|
3,701
|
|
|
2,327
|
Natural gas (MMcf)
|
|
|
7,642
|
|
|
7,193
|
|
|
24,639
|
|
|
28,472
|
Total barrels of oil equivalent (MBoe)
|
|
|
6,286
|
|
|
5,742
|
|
|
22,040
|
|
|
19,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily production volumes by product -
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (Bbls/d)
|
|
|
43,040
|
|
|
40,206
|
|
|
38,992
|
|
|
34,428
|
NGLs (Bbls/d)
|
|
|
11,443
|
|
|
9,181
|
|
|
10,139
|
|
|
6,376
|
Natural gas (Mcf/d)
|
|
|
83,067
|
|
|
78,182
|
|
|
67,503
|
|
|
78,006
|
Total barrels of oil equivalent (Boe/d)
|
|
|
68,328
|
|
|
62,417
|
|
|
60,382
|
|
|
53,805
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily production volumes by region (Boe/d) -
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford
|
|
|
38,628
|
|
|
41,555
|
|
|
37,591
|
|
|
37,825
|
Delaware Basin
|
|
|
29,655
|
|
|
15,145
|
|
|
22,609
|
|
|
6,713
|
Other
|
|
|
45
|
|
|
5,717
|
|
|
182
|
|
|
9,267
|
Total barrels of oil equivalent (Boe/d)
|
|
|
68,328
|
|
|
62,417
|
|
|
60,382
|
|
|
53,805
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices -
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil ($ per Bbl)
|
|
|
$58.66
|
|
|
$56.84
|
|
|
$64.05
|
|
|
$50.39
|
NGLs ($ per Bbl)
|
|
|
$23.38
|
|
|
$23.35
|
|
|
$26.10
|
|
|
$20.37
|
Natural gas ($ per Mcf)
|
|
|
$2.14
|
|
|
$2.34
|
|
|
$2.35
|
|
|
$2.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CARRIZO OIL & GAS, INC.
|
COMMODITY DERIVATIVE CONTRACTS - AS OF FEBRUARY 22, 2019
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
|
|
|
Sub-Floor
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
|
|
|
Price
|
|
|
Price
|
|
|
Price
|
|
|
Price
|
|
|
Differential
|
|
|
|
|
|
|
|
|
|
|
|
|
(Bbls
|
|
|
($ per
|
|
|
($ per
|
|
|
($ per
|
|
|
($ per
|
|
|
($ per
|
Commodity
|
|
|
Period
|
|
|
Type of Contract
|
|
|
Index
|
|
|
(per day)
|
|
|
Bbl)
|
|
|
Bbl)
|
|
|
Bbl)
|
|
|
Bbl)
|
|
|
Bbl)
|
Crude oil
|
|
|
1Q19
|
|
|
Three-Way Collars
|
|
|
NYMEX WTI
|
|
|
27,000
|
|
|
—
|
|
|
$41.67
|
|
|
$50.96
|
|
|
$74.23
|
|
|
—
|
|
Crude oil
|
|
|
1Q19
|
|
|
Basis Swaps
|
|
|
LLS-WTI Cushing
|
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$5.16
|
|
Crude oil
|
|
|
1Q19
|
|
|
Basis Swaps
|
|
|
WTI Midland-WTI Cushing
|
|
|
5,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
($5.24
|
)
|
Crude oil
|
|
|
1Q19
|
|
|
Sold Call Options
|
|
|
NYMEX WTI
|
|
|
3,875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$81.07
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
2Q19
|
|
|
Three-Way Collars
|
|
|
NYMEX WTI
|
|
|
27,000
|
|
|
—
|
|
|
$41.67
|
|
|
$50.96
|
|
|
$74.23
|
|
|
—
|
|
Crude oil
|
|
|
2Q19
|
|
|
Basis Swaps
|
|
|
LLS-WTI Cushing
|
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$5.16
|
|
Crude oil
|
|
|
2Q19
|
|
|
Basis Swaps
|
|
|
WTI Midland-WTI Cushing
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($5.38
|
)
|
Crude oil
|
|
|
2Q19
|
|
|
Sold Call Options
|
|
|
NYMEX WTI
|
|
|
3,875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$81.07
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
3Q19
|
|
|
Three-Way Collars
|
|
|
NYMEX WTI
|
|
|
27,000
|
|
|
—
|
|
|
$41.67
|
|
|
$50.96
|
|
|
$74.23
|
|
|
—
|
|
Crude oil
|
|
|
3Q19
|
|
|
Basis Swaps
|
|
|
LLS-WTI Cushing
|
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$5.16
|
|
Crude oil
|
|
|
3Q19
|
|
|
Basis Swaps
|
|
|
WTI Midland-WTI Cushing
|
|
|
7,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($5.56
|
)
|
Crude oil
|
|
|
3Q19
|
|
|
Sold Call Options
|
|
|
NYMEX WTI
|
|
|
3,875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$81.07
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
4Q19
|
|
|
Three-Way Collars
|
|
|
NYMEX WTI
|
|
|
27,000
|
|
|
—
|
|
|
$41.67
|
|
|
$50.96
|
|
|
$74.23
|
|
|
—
|
|
Crude oil
|
|
|
4Q19
|
|
|
Basis Swaps
|
|
|
LLS-WTI Cushing
|
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$5.16
|
|
Crude oil
|
|
|
4Q19
|
|
|
Basis Swaps
|
|
|
WTI Midland-WTI Cushing
|
|
|
11,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($3.84
|
)
|
Crude oil
|
|
|
4Q19
|
|
|
Sold Call Options
|
|
|
NYMEX WTI
|
|
|
3,875
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$81.07
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
2020
|
|
|
Price Swaps
|
|
|
NYMEX WTI
|
|
|
3,000
|
|
|
$55.06
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
2020
|
|
|
Three-Way Collars
|
|
|
NYMEX WTI
|
|
|
6,000
|
|
|
—
|
|
|
$45.00
|
|
|
$55.00
|
|
|
$64.69
|
|
|
—
|
|
Crude oil
|
|
|
2020
|
|
|
Basis Swaps
|
|
|
WTI Midland-WTI Cushing
|
|
|
13,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
($1.27
|
)
|
Crude oil
|
|
|
2020
|
|
|
Sold Call Options
|
|
|
NYMEX WTI
|
|
|
4,575
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$75.98
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
2021
|
|
|
Basis Swaps
|
|
|
WTI Midland-WTI Cushing
|
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$0.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
|
|
|
Sub-Floor
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
|
|
|
Price
|
|
|
Price
|
|
|
Price
|
|
|
Price
|
|
|
Differential
|
|
|
|
|
|
|
|
|
|
|
|
|
(MMBtu
|
|
|
($ per
|
|
|
($ per
|
|
|
($ per
|
|
|
($ per
|
|
|
($ per
|
Commodity
|
|
|
Period
|
|
|
Type of Contract
|
|
|
Index
|
|
|
(per day)
|
|
|
MMBtu)
|
|
|
MMBtu)
|
|
|
MMBtu)
|
|
|
MMBtu)
|
|
|
MMBtu)
|
Natural gas
|
|
|
1Q19
|
|
|
Sold Call Options
|
|
|
NYMEX Henry Hub
|
|
|
33,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$3.25
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
2Q19
|
|
|
Sold Call Options
|
|
|
NYMEX Henry Hub
|
|
|
33,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$3.25
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
3Q19
|
|
|
Sold Call Options
|
|
|
NYMEX Henry Hub
|
|
|
33,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$3.25
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
4Q19
|
|
|
Sold Call Options
|
|
|
NYMEX Henry Hub
|
|
|
33,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$3.25
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
2020
|
|
|
Sold Call Options
|
|
|
NYMEX Henry Hub
|
|
|
33,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$3.50
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CARRIZO OIL & GAS, INC.
|
FIRST QUARTER AND FULL YEAR 2019 GUIDANCE SUMMARY
|
|
|
|
|
|
|
|
|
|
|
First Quarter 2019
|
|
|
Full Year 2019
|
Daily Production Volumes (Boe/d)
|
|
|
61,100 - 62,100
|
|
|
66,800 - 67,800
|
Crude oil
|
|
|
64%
|
|
|
63%
|
NGLs
|
|
|
17%
|
|
|
17%
|
Natural gas
|
|
|
19%
|
|
|
20%
|
|
|
|
|
|
|
|
Unhedged Commodity Price Realizations
|
|
|
|
|
|
|
Crude oil (% of NYMEX oil)
|
|
|
99.0% - 101.0%
|
|
|
N/A
|
NGLs (% of NYMEX oil)
|
|
|
37.0% - 39.0%
|
|
|
N/A
|
Natural gas (% of NYMEX gas)
|
|
|
76.0% - 78.0%
|
|
|
N/A
|
|
|
|
|
|
|
|
Cash paid for derivative settlements, net ($MM)
|
|
|
($3.5) - ($2.5)
|
|
|
N/A
|
|
|
|
|
|
|
|
Costs and Expenses -
|
|
|
|
|
|
|
Lease operating ($/Boe)
|
|
|
$7.50 - $8.00
|
|
|
$7.00 - $7.75
|
Production and ad valorem taxes (% of total revenues)
|
|
|
6.50% - 7.00%
|
|
|
6.00% - 7.00%
|
Cash general and administrative, net ($MM)
|
|
|
$21.0 - $22.0
|
|
|
$51.0 - $53.0
|
Depreciation, depletion and amortization ($/Boe)
|
|
|
$13.00 - $14.00
|
|
|
$13.00 - $14.00
|
Interest expense, net ($MM)
|
|
|
$16.3 - $17.3
|
|
|
N/A
|
|
|
|
|
|
|
|
Capital Expenditures -
|
|
|
|
|
|
|
Drilling, completion, and infrastructure ($MM)
|
|
|
N/A
|
|
|
$525.0 - $575.0
|
Interest ($MM)
|
|
|
$8.5 - $9.0
|
|
|
N/A
|
|
|
|
|
|
|
|
View source version on businesswire.com: https://www.businesswire.com/news/home/20190225005905/en/ Copyright Business Wire 2019
Source: Business Wire
(February 25, 2019 - 4:05 PM EST)
News by QuoteMedia
www.quotemedia.com
|