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
- Total production of 68,328 Boe/d, 9%
above the fourth quarter of 2017 and 6% above the third quarter of
2018
- 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
- 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
- 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
$3.10/MMBtu, before adjustment for differentials.
Crude Oil NGLs Natural Gas Total
PV-10 Region (MMBbl)
(MMBbl) (Bcf)
(MMBoe) ($MM) Eagle Ford Shale 110.9
19.2 114.1 149.1 $ 2,691.8 Delaware Basin 68.8 49.9
369.0 180.3
1,399.6
Total 179.7 69.1
483.1 329.4
$ 4,091.4
The table below summarizes the changes in the Company’s proved
reserves during 2018.
Crude
Oil NGLs Natural Gas Total (MMBbl)
(MMBbl) (Bcf)
(MMBoe) Proved reserves - December 31, 2017
167.4 42.6 310.5 261.7 Extensions and
discoveries 65.3 30.2 212.8 131.0 Removed due to changes in
development plan (16.2 ) (2.8 ) (16.8 ) (21.8 ) Revisions of
previous estimates (15.1 ) 4.7 10.8 (8.5 ) Purchases of reserves in
place 2.2 1.0 7.9 4.5 Divestitures of reserves in place (9.7 ) (2.9
) (17.5 ) (15.5 ) Production (14.2 ) (3.7 )
(24.6 ) (22.0 )
Proved reserves - December
31, 2018 179.7 69.1
483.1 329.4
Proved developed - December 31, 2018 75.3 25.8
178.9 130.9
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.
Total ($MM) Property acquisition costs
Proved properties $47.4 Unproved properties 182.2 Total
property acquisition costs 229.6 Exploration costs 48.6 Development
costs 809.6
Total costs incurred (1)
$1,087.8
__________
(1) Total costs incurred includes capitalized general
and administrative expense and asset retirement obligations and
excludes capitalized interest.
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 EndedDecember
31,
Years EndedDecember 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
AdditionalPaid-inCapital
AccumulatedDeficit
TotalShareholders’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 EndedDecember
31,
Years EndedDecember 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 EndedDecember
31,
Years EndedDecember 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 EndedDecember
31,
Years EndedDecember 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 EndedDecember
31,
Years EndedDecember 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/
Carrizo Oil & Gas, Inc.Jeffrey P. Hayden,
CFAVP - Investor Relations(713)
328-1044orKim PinyopusarerkManager - Investor
Relations(713) 358-6430
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