Carrizo Oil & Gas, Inc. (Nasdaq:CRZO) today
announced the Company’s financial results for the fourth quarter of
2016 and provided an operational update, which includes the
following highlights:
- Crude oil production of 28,727 Bbls/d, 15% above the
fourth quarter of 2015
- Total production of 44,775 Boe/d, 11% above the fourth
quarter of 2015
- Loss From Continuing Operations of $0.8 million, or
$0.01 per diluted share, and Net Cash Provided by Operating
Activities From Continuing Operations of $74.9
million
- Adjusted Net Income of $28.4 million, or $0.44 per
diluted share, and Adjusted EBITDA of $118.1 million
- 291% reserve replacement from all sources at a finding,
development, and acquisition (FD&A) cost of $13.65 per
Boe
- 2017 drilling and completion capital expenditure
guidance of $530-$550 million
- 2017 crude oil production growth target of
23%
- Three-year compound annual crude oil production growth
target of more than 20%
- Increasing Eagle Ford Shale inventory by more than 10%
based on additional successful downspacing pilots
Carrizo reported a fourth quarter of 2016 loss
from continuing operations of $0.8 million, or $0.01 per basic and
diluted share compared to a loss from continuing operations of
$380.7 million, or $6.73 per basic and diluted share in the fourth
quarter of 2015. The loss from continuing operations for the fourth
quarter of 2016 includes certain items typically excluded from
published estimates by the investment community. Adjusted net
income, which excludes the impact of these items as described in
the non-GAAP reconciliation tables included below, for the fourth
quarter of 2016 was $28.4 million, or $0.44 per diluted share,
respectively, compared to $18.5 million, or $0.32 per diluted
share, respectively, in the fourth quarter of 2015.
For the fourth quarter of 2016, Adjusted EBITDA
was $118.1 million, an increase of 5% from the prior year quarter
due to higher production volumes and commodity prices. Adjusted
EBITDA and the reconciliation to loss from continuing operations
are presented in the non-GAAP reconciliation tables included
below.
Production volumes during the fourth quarter of
2016 were 4,119 MBoe, or 44,775 Boe/d, an increase of 11% versus
the fourth quarter of 2015. The year-over-year production growth
was driven by continued strong results from the Company’s Eagle
Ford Shale assets as well as a ramp up from its Delaware Basin
assets. Oil production during the fourth quarter of 2016 averaged
28,727 Bbls/d, an increase of 15% versus the fourth quarter of
2015; natural gas and NGL production averaged 65,999 Mcf/d and
5,048 Bbls/d, respectively, during the fourth quarter of 2016.
Fourth quarter of 2016 production exceeded the high end of Company
guidance due primarily to stronger-than-expected performance from
the Company’s Eagle Ford Shale and Delaware Basin assets.
Drilling and completion capital expenditures for
the fourth quarter of 2016 were $92.0 million. More than 85% of the
fourth quarter drilling and completion spending was in the Eagle
Ford Shale, with the balance weighted towards the Delaware Basin
and Niobrara Formation. Land and seismic expenditures during the
quarter were $7.9 million, excluding the previously-announced
acquisition from Sanchez Energy Corporation.
For 2017, Carrizo is providing initial drilling
and completion capital expenditure guidance of $530-$550 million.
This level of spending incorporates an assumed increase in oilfield
service costs during the year and should allow the Company to run
three rigs in the Eagle Ford as well as continue to develop its
acreage in the Delaware Basin. During 2016, Carrizo adjusted its
development plan for the Eagle Ford to incorporate even larger pads
than it had in prior years, and the Company expects to continue
utilizing larger pads going forward. While this is expected to
result in a more efficient development of the Company's Eagle Ford
assets, it is also likely to result in more uneven production
growth on a quarterly basis. The Company's initial land and seismic
capital expenditure guidance is $20 million.
Based on this level of activity, Carrizo is
providing initial 2017 oil production guidance of 31,400-31,900
Bbls/d. Using the midpoint of this range, the Company’s 2017 oil
production growth guidance is 23%. For natural gas and NGLs,
Carrizo is providing initial 2017 guidance of 69-73 MMcf/d and
5,600-5,900 Bbls/d, respectively. For the first quarter of 2017,
Carrizo expects oil production to be 27,700-28,100 Bbls/d, and
natural gas and NGL production to be 72-76 MMcf/d and 4,700-4,900
Bbls/d, respectively. A full summary of Carrizo’s guidance is
provided in the attached tables.
Carrizo is also providing guidance on its
three-year plan, which is designed to generate strong, economical
production growth while also improving the Company's balance sheet.
Based on a three-rig program in the Eagle Ford, complemented by
activity in the Company's other operating areas, Carrizo expects to
deliver a three-year compound annual growth rate of more than 20%
for its crude oil production. Based on the current commodity price
strip, this plan is also expected to reduce the Company's leverage
ratio over the period.
S.P. “Chip” Johnson, IV, Carrizo’s President and
CEO, commented on the results, “We finished 2016 with another
strong quarter operationally, with production again exceeding our
forecast. During the commodity price downturn of the last couple of
years our primary focus was on managing our balance sheet, while
remaining in a strong operational position that would allow us to
quickly re-accelerate production growth as prices improved. And I
believe our team did a great job on both fronts. As a result, we
recently elected to add a third full-time rig to our Eagle Ford
Shale properties, which should drive a crude oil production growth
rate for 2017 that is approximately twice the rate we grew last
year.
“During 2016, Carrizo once again generated
strong reserve growth. Our proved reserves grew by approximately
17% during the year, with the Eagle Ford Shale and Delaware Basin
accounting for the majority of the reserve additions. This is
despite the SEC crude oil price deck for the year being
approximately 15% below the 2015 level.
“We have continued to expand our inventory of
de-risked drilling locations in the Eagle Ford Shale. Additional
stagger-stack pilots have performed well, so we are moving the
stagger stack to development mode in two more areas. We also
successfully tested an infill pilot on our LaSalle County acreage,
where we saw good performance from the new well as well as a
positive response from the offsetting parent wells. As a result of
these initiatives, we are increasing our estimate of net de-risked
drilling locations in the Eagle Ford Shale to more than 1,200, or
10-15 years of inventory at our current drilling pace.
“We have a deep inventory of high-quality,
de-risked drilling locations not just in the Eagle Ford, but in our
other areas as well. And we are confident that we will be able to
continue to expand our drilling inventory through both organic
efforts as well as additional acquisitions. Given this visibility,
we're pleased to announce a three-year plan that is expected to
deliver a compound annual growth rate of more than 20% for our
crude oil production while also reducing our leverage over the
period.”
2016 Proved Reserves
The Company’s proved reserves as of December 31,
2016 were 200.2 MMBoe, a 17% increase over year-end 2015, including
a record 128.4 MMBbls of crude oil, a 17% increase over year-end
2015. The Company’s PV-10 value was $1.3 billion as of December 31,
2016.
The table below summarizes the Company’s
year-end 2016 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,
2016 based on the West Texas Intermediate benchmark crude oil price
of $42.75/Bbl and the Henry Hub benchmark natural gas price of
$2.49/MMBtu, before adjustment for differentials.
| |
|
Crude Oil |
NGLs |
Natural Gas |
Total |
PV-10 |
|
Region |
|
(MMBbl) |
(MMBbl) |
(Bcf) |
(MMBoe) |
($MM) |
| Eagle Ford |
|
120.9 |
|
20.5 |
|
125.4 |
|
162.3 |
|
$1,187.8 |
|
| Delaware Basin |
|
4.9 |
|
2.7 |
|
24.8 |
|
11.7 |
|
|
37.4 |
|
| Niobrara |
|
2.1 |
|
0.3 |
|
2.0 |
|
2.7 |
|
|
24.5 |
|
| Marcellus |
|
— |
|
— |
|
130.9 |
|
21.8 |
|
|
43.5 |
|
| Utica |
|
0.5 |
|
0.4 |
|
4.4 |
|
1.7 |
|
|
10.2 |
|
|
Total |
|
128.4 |
|
23.9 |
|
287.5 |
|
200.2 |
|
$1,303.4 |
|
The table below summarizes the changes in the
Company’s proved reserves during 2016.
| |
|
Crude Oil |
NGLs |
Natural Gas |
Total |
| |
|
(MMBbl) |
(MMBbl) |
(Bcf) |
(MMBoe) |
| Proved reserves
- December 31, 2015 |
|
109.6 |
|
20.2 |
|
244.9 |
|
170.6 |
|
| Revisions of previous
estimates |
|
(16.7 |
) |
(3.2 |
) |
1.6 |
|
(19.6 |
) |
| Extensions and
discoveries |
|
40.1 |
|
8.6 |
|
59.3 |
|
58.6 |
|
| Purchases of reserves
in place |
|
4.8 |
|
0.1 |
|
7.3 |
|
6.1 |
|
| Production |
|
(9.4 |
) |
(1.8 |
) |
(25.6 |
) |
(15.5 |
) |
| Proved reserves
- December 31, 2016 |
|
128.4 |
|
23.9 |
|
287.5 |
|
200.2 |
|
| Proved
developed - December 31, 2016 |
|
51.1 |
|
9.4 |
|
187.1 |
|
91.6 |
|
The following table summarizes the Company’s
costs incurred in oil and gas property acquisition, exploration,
and development activities for the year ended December 31,
2016.
| |
|
Total |
| |
|
($MM) |
| Property acquisition
costs |
|
|
| Proved
properties |
|
$90.7 |
|
| Unproved
properties |
|
|
113.5 |
|
| Total
property acquisition costs |
|
|
204.2 |
|
| Exploration costs |
|
|
37.5 |
|
| Development costs |
|
|
374.1 |
|
| Total costs
incurred (1) |
|
$615.8 |
|
_________
(1) Total costs incurred includes capitalized general and
administrative expense and asset retirement obligations and
excludes capitalized interest.
2016 highlights include:
- Total reserve replacement was 291% at an all-sources FD&A
cost of $13.65 per Boe
- Drill-bit reserve replacement was 252% at an F&D cost of
$10.55 per Boe
- Excluding negative price-related revisions of 6.7 MMBoe,
drill-bit reserve replacement was 295% at an F&D cost of $9.01
per Boe
- Eagle Ford reserves increased to 162.3 MMBoe, a 13% increase
from the 144.0 MMBoe at year-end 2015
- Crude oil represents 64% of total proved reserves and 86% of
the total PV-10 value at December 31, 2016
- Proved developed reserves increased to 91.6 MMBoe at year-end
2016, a 21% increase from the 76.0 MMBoe at year-end 2015
- 46% of total proved reserves at December 31, 2016 are
classified as proved developed, compared to 45% at year-end
2015
Operational Update
In the Eagle Ford Shale, Carrizo drilled 23
gross (22.9 net) operated wells during the fourth quarter and
completed 14 gross (13.3 net) wells. Crude oil production from the
play was approximately 25,100 Bbls/d for the quarter, up 16% versus
the prior quarter. At the end of the quarter, Carrizo had 35 gross
(33.4 net) operated Eagle Ford wells waiting on completion,
equating to net crude oil production potential of more than 12,500
Bbls/d. The Company is currently operating three rigs in the Eagle
Ford and expects to drill approximately 107 gross (92 net) operated
wells and complete 99 gross (87 net) operated wells in the play
during 2017.
Carrizo continues to test multiple initiatives
aimed at determining the optimal development spacing on its acreage
position, including the Company’s ongoing stagger-stack pilots and
a recent infill test. The Company currently has nine stagger-stack
pilots on production across its Core acreage position in the Eagle
Ford Shale, with these pilots testing effective lateral spacing
ranging from 200 ft. to 285 ft. At the RPG project, the Company has
four pilots testing 250 ft. effective lateral spacing. Early
results from these pilots have been encouraging with production
meeting or exceeding production from nearby wells drilled at 330
ft. spacing. At Irvin Ranch, the Company has three pilots testing
effective lateral spacing ranging from 200 ft. to 285 ft.
Performance from these pilots continues to improve, and Carrizo
believes that at a stagger stack development is optimal for this
portion of the asset. The Company plans to conduct additional
spacing pilots at Irvin Ranch before moving the rest of the
potential locations into its de-risked inventory. Carrizo currently
has three additional pilots in other core project areas that are
currently being drilled and completed.
The Company’s first infill test, the Irvin Ranch
1H, was drilled between two wells that were completed in December
2011 and have produced more than 375 Mbo. The infill well was
completed in late 2015, and has produced 75 Mbo to date from a
4,800 ft. lateral. At current well costs and projected EURs, the
expected IRR for a similar well is over 80% at current commodity
price levels. Additionally, Carrizo observed a positive production
response from the parent wells offsetting the Irvin 1H, which
produced approximately 15 Mbo of incremental oil after completion
of the infill well.
Based on the results from these spacing
initiatives, Carrizo is adding more than 120 net locations to its
estimate of de-risked inventory in the Eagle Ford Shale. This
brings the Company's current estimate of net de-risked locations on
its acreage position to more than 1,200 locations.
In addition to conducting spacing optimization
tests on its acreage, the Company has also been testing various
completion optimization techniques. During 2016, the Company began
testing tighter frac stage spacing in its Eagle Ford Shale wells,
reducing the stage spacing to 200 ft. from 240 ft. To date, Carrizo
has completed 28 wells with the tighter stage spacing, with the
tighter stage-spaced wells outperforming the wider stage-spaced
wells by approximately 10%. The wells with the tighter stage
spacing also appear to minimize the frac interference between the
new wells and the offsetting parent wells, which should further
enhance the economics of the Company's development program. Based
on the success from the 200 ft. stage-spaced wells, the Company is
currently testing completions with even tighter stage spacing.
In the Delaware Basin, Carrizo drilled two
operated wells during the fourth quarter, both located on the
western side of its acreage position. Carrizo currently plans to
complete these wells as part of its 2017 program. Crude oil
production from the play was more than 1,200 Bbls/d for the
quarter, up more than 65% versus the prior quarter. Carrizo
currently plans to drill approximately 6 gross (4 net) operated
wells and complete 6 gross (5 net) operated wells in the Delaware
Basin during 2017.
The Company’s most recent operated completion in
the Delaware Basin was the Fortress State 1H, which was brought
online late in the third quarter. The well was drilled with an
approximate 6,100 ft. lateral and completed with 27 frac stages.
The well achieved a peak 30-day rate of 1,520 Boe/d (25% oil, 36%
gas, 39% NGL) on a restricted choke. Carrizo operates the Fortress
State 1H with a 93% working interest.
In the Niobrara Formation, Carrizo did not drill
or complete any operated wells during the fourth quarter. Crude oil
production from the play was more than 2,200 Bbls/d for the
quarter, up more than 20% from the prior quarter as a result of the
Company's completion activity during the third quarter of 2016.
Carrizo is not currently budgeting any operated activity in the
Niobrara during 2017. However, based on recent improvements in
well-level economics, the Company will continue to evaluate
resuming operated development activity later in 2017 or in 2018.
Carrizo expects to continue participating in non-operated activity
within its focus area during 2017.
In Appalachia, which encompasses the Company's
Utica Shale and Marcellus Shale positions, Carrizo did not drill or
complete any operated wells during the fourth quarter. Oil and
condensate production from the Utica was more than 200 Bbls/d
during the quarter, down from approximately 250 Bbls/d in the prior
quarter due to the lack of activity. In the Marcellus, the
Company's production was 35.8 MMcf/d, down from 40.9 MMcf/d in the
prior quarter due to significant voluntary production curtailments
during October given the extremely weak local market price
environment. Carrizo expects to continue to vary its Marcellus
production during 2017 based on local market pricing. Carrizo has
currently allocated only a minimal amount of maintenance capital to
Appalachia during 2017.
Hedging Activity
Carrizo currently has hedges in place for more
than 25% of estimated crude oil production for 2017 (based on the
midpoint of guidance). For the year, the Company has swaps covering
approximately 8,200 Bbls/d of crude oil at an average fixed price
of approximately $51.30/Bbl. Additionally, Carrizo has swaps
covering 20,000 MMBtu/d for the year at an average fixed price of
$3.30/MMBtu. (Please refer to the attached tables for details of
the Company’s derivative contracts.)
Conference Call Details
The Company will hold a conference call to
discuss 2016 fourth quarter financial results on Thursday, February
23, 2017 at 10:00 AM Central Standard Time. To participate in the
call, please dial (888) 225-8168 (U.S. & Canada) or
+1 (303) 223-4367 (Intl.) ten minutes before the call is
scheduled to begin. A replay of the call will be available through
Thursday, March 2, 2017 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 21843646 for
U.S., Canadian, and International callers.
A simultaneous webcast of the call may be
accessed over the internet by visiting our website at
http://www.carrizo.com, clicking on “Upcoming Events”, and then
clicking on the “2016 Fourth Quarter and Year-end Conference Call”
link. To listen, please go to the website in time to register and
install any necessary software. The webcast will be archived for
replay on the Carrizo website for 7 days.
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, the Delaware Basin in West Texas, the
Niobrara Formation in Colorado, the Utica Shale in Ohio, and the
Marcellus Shale in Pennsylvania.
Statements in this release that are not
historical facts, including but not limited to those related to
capital requirements, capital expenditure and other spending plans,
the three-year plan including effects thereof, economical basis of
wells or inventory, rig program, effect of transactions offsetting
hedge positions, production, average well returns, the estimated
production results and financial performance of such properties,
effects of transactions, targeted ratios and other metrics, the
ability to acquire additional acreage, midstream infrastructure
availability and capacity, timing, levels of and potential
production, downspacing, crude oil production potential and growth,
oil and gas prices, drilling and completion activities, drilling
inventory, including timing thereof, resource potential, well
costs, breakeven prices, production mix, development plans, growth,
midstream matters, use of proceeds, hedging activity, the ability
to maintain a sound financial position, 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, expected income tax
rates and other statements that are not historical facts are
forward-looking statements that are based on current expectations.
Although the Company believes that its expectations are based on
reasonable assumptions, it can give no assurance that these
expectations will prove correct. Important factors that could cause
actual results to differ materially from those in the
forward-looking statements include assumptions regarding well
costs, estimated recoveries, pricing and other factors affecting
average well returns, the need to obtain board approval of
expenditures in the three-year plan, results of wells and testing,
failure of actual production to meet expectations, performance of
rig operators, spacing test results, availability of gathering
systems, costs of oilfield services, actions by governmental
authorities, joint venture partners, industry partners, lenders and
other third parties, actions by purchasers or sellers of
properties, satisfaction of closing conditions and failure of the
acquisition to close, purchase price adjustment, integration and
effects of acquisitions, 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, 2015 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
data) |
| (Unaudited) |
| |
|
|
|
|
| |
|
December 31, |
| |
|
|
2016 |
|
|
2015 |
|
Assets |
|
|
|
|
| Current assets |
|
|
|
|
| Cash and
cash equivalents |
|
$4,194 |
|
|
$42,918 |
|
| Accounts
receivable, net |
|
|
64,208 |
|
|
|
54,721 |
|
|
Derivative assets |
|
|
1,237 |
|
|
|
131,100 |
|
| Other
current assets |
|
|
3,349 |
|
|
|
3,443 |
|
| Total
current assets |
|
|
72,988 |
|
|
|
232,182 |
|
| Property and
equipment |
|
|
|
|
| Oil and
gas properties, full cost method |
|
|
|
|
| Proved
properties, net |
|
|
1,294,667 |
|
|
|
1,369,151 |
|
| Unproved
properties, not being amortized |
|
|
240,961 |
|
|
|
335,452 |
|
| Other
property and equipment, net |
|
|
10,132 |
|
|
|
12,258 |
|
| Total
property and equipment, net |
|
|
1,545,760 |
|
|
|
1,716,861 |
|
| Deferred income
taxes |
|
|
— |
|
|
|
46,758 |
|
| Derivative assets |
|
|
— |
|
|
|
1,115 |
|
| Other assets |
|
|
7,579 |
|
|
|
10,330 |
|
| Total
Assets |
|
$1,626,327 |
|
|
$2,007,246 |
|
| |
|
|
|
|
| Liabilities and
Shareholders’ Equity |
|
|
|
|
| Current
liabilities |
|
|
|
|
| Accounts
payable |
|
$55,631 |
|
|
$74,065 |
|
| Revenues
and royalties payable |
|
|
38,107 |
|
|
|
67,808 |
|
| Accrued
capital expenditures |
|
|
36,594 |
|
|
|
39,225 |
|
| Accrued
interest |
|
|
22,016 |
|
|
|
21,981 |
|
| Accrued
lease operating expense |
|
|
12,377 |
|
|
|
11,588 |
|
|
Liabilities of discontinued operations |
|
|
— |
|
|
|
2,666 |
|
| Deferred
income taxes |
|
|
— |
|
|
|
46,758 |
|
|
Derivative liabilities |
|
|
22,601 |
|
|
|
— |
|
| Other
current liabilities |
|
|
24,633 |
|
|
|
21,393 |
|
| Total
current liabilities |
|
|
211,959 |
|
|
|
285,484 |
|
| Long-term debt |
|
|
1,325,418 |
|
|
|
1,236,017 |
|
| Liabilities of
discontinued operations |
|
|
— |
|
|
|
1,088 |
|
| Asset retirement
obligations |
|
|
20,848 |
|
|
|
16,183 |
|
| Derivative
liabilities |
|
|
27,528 |
|
|
|
12,648 |
|
| Other liabilities |
|
|
17,116 |
|
|
|
11,772 |
|
| Total
liabilities |
|
|
1,602,869 |
|
|
|
1,563,192 |
|
| Commitments and
contingencies |
|
|
|
|
| Shareholders’
equity |
|
|
|
|
| Common
stock, $0.01 par value, 90,000,000 shares authorized; 65,132,499
issued and outstanding as of December 31, 2016 and 58,332,993
issued and outstanding as of December 31, 2015 |
|
|
651 |
|
|
|
583 |
|
|
Additional paid-in capital |
|
|
1,665,891 |
|
|
|
1,411,081 |
|
|
Accumulated deficit |
|
|
(1,643,084 |
) |
|
|
(967,610 |
) |
| Total
shareholders’ equity |
|
|
23,458 |
|
|
|
444,054 |
|
| Total
Liabilities and Shareholders’ Equity |
|
$1,626,327 |
|
|
$2,007,246 |
|
| CARRIZO OIL & GAS, INC. |
| CONSOLIDATED STATEMENTS OF
OPERATIONS |
| (In thousands, except per share
data) |
| (Unaudited) |
| |
|
|
|
|
|
|
|
| |
Three Months Ended December
31, |
|
Years Ended December 31, |
| |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
Revenues |
|
|
|
|
|
|
|
| Crude
oil |
$123,315 |
|
|
$86,542 |
|
|
$378,073 |
|
|
$376,094 |
|
| Natural
gas liquids |
|
7,309 |
|
|
|
4,006 |
|
|
|
22,428 |
|
|
|
15,608 |
|
| Natural
gas |
|
13,207 |
|
|
|
8,874 |
|
|
|
43,093 |
|
|
|
37,501 |
|
| Total
revenues |
|
143,831 |
|
|
|
99,422 |
|
|
|
443,594 |
|
|
|
429,203 |
|
| |
|
|
|
|
|
|
|
| Costs and
Expenses |
|
|
|
|
|
|
|
| Lease
operating |
|
27,646 |
|
|
|
22,748 |
|
|
|
98,717 |
|
|
|
90,052 |
|
|
Production taxes |
|
6,106 |
|
|
|
4,370 |
|
|
|
19,046 |
|
|
|
17,683 |
|
| Ad
valorem taxes |
|
1,609 |
|
|
|
2,243 |
|
|
|
5,559 |
|
|
|
9,255 |
|
|
Depreciation, depletion and amortization |
|
53,470 |
|
|
|
65,577 |
|
|
|
213,962 |
|
|
|
300,035 |
|
| General
and administrative, net |
|
15,926 |
|
|
|
12,345 |
|
|
|
74,972 |
|
|
|
67,224 |
|
| (Gain)
loss on derivatives, net |
|
19,135 |
|
|
|
(56,665 |
) |
|
|
49,073 |
|
|
|
(99,261 |
) |
| Interest
expense, net |
|
20,490 |
|
|
|
17,792 |
|
|
|
79,403 |
|
|
|
69,195 |
|
|
Impairment of proved oil and gas properties |
|
— |
|
|
|
411,615 |
|
|
|
576,540 |
|
|
|
1,224,367 |
|
| Loss on
extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
38,137 |
|
| Other
expense, net |
|
228 |
|
|
|
487 |
|
|
|
1,796 |
|
|
|
11,276 |
|
| Total
costs and expenses |
|
144,610 |
|
|
|
480,512 |
|
|
|
1,119,068 |
|
|
|
1,727,963 |
|
| |
|
|
|
|
|
|
|
| Loss From
Continuing Operations Before Income Taxes |
|
(779 |
) |
|
|
(381,090 |
) |
|
|
(675,474 |
) |
|
|
(1,298,760 |
) |
| Income tax benefit |
|
— |
|
|
|
419 |
|
|
|
— |
|
|
|
140,875 |
|
| Loss From
Continuing Operations |
|
(779 |
) |
|
|
(380,671 |
) |
|
|
(675,474 |
) |
|
|
(1,157,885 |
) |
| Income From
Discontinued Operations, Net of Income Taxes |
|
— |
|
|
|
506 |
|
|
|
— |
|
|
|
2,731 |
|
| Net
Loss |
($779 |
) |
|
($380,165 |
) |
|
($675,474 |
) |
|
($1,155,154 |
) |
| |
|
|
|
|
|
|
|
| Net Loss Per
Common Share - Basic |
|
|
|
|
|
|
|
| Loss from continuing
operations |
($0.01 |
) |
|
($6.73 |
) |
|
($11.27 |
) |
|
($22.50 |
) |
| Income from
discontinued operations, net of income taxes |
|
— |
|
|
|
0.01 |
|
|
|
— |
|
|
|
0.05 |
|
| Net loss |
($0.01 |
) |
|
($6.72 |
) |
|
($11.27 |
) |
|
($22.45 |
) |
| |
|
|
|
|
|
|
|
| Net Loss Per
Common Share - Diluted |
|
|
|
|
|
|
|
| Loss from continuing
operations |
($0.01 |
) |
|
($6.73 |
) |
|
($11.27 |
) |
|
($22.50 |
) |
| Income from
discontinued operations, net of income taxes |
|
— |
|
|
|
0.01 |
|
|
|
— |
|
|
|
0.05 |
|
| Net loss |
($0.01 |
) |
|
($6.72 |
) |
|
($11.27 |
) |
|
($22.45 |
) |
| |
|
|
|
|
|
|
|
| Weighted
Average Common Shares Outstanding |
|
|
|
|
|
|
|
| Basic |
|
63,587 |
|
|
|
56,544 |
|
|
|
59,932 |
|
|
|
51,457 |
|
| Diluted |
|
63,587 |
|
|
|
56,544 |
|
|
|
59,932 |
|
|
|
51,457 |
|
| CARRIZO OIL & GAS, INC. |
| CONSOLIDATED STATEMENTS OF CASH
FLOWS |
| (In thousands) |
| (Unaudited) |
| |
|
|
|
|
|
|
|
| |
Three Months Ended December
31, |
|
Years Ended December 31, |
| |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
| Cash Flows From
Operating Activities |
|
|
|
|
|
|
|
| Net loss |
($779 |
) |
|
($380,165 |
) |
|
($675,474 |
) |
|
($1,155,154 |
) |
| Income from
discontinued operations, net of income taxes |
|
— |
|
|
|
(506 |
) |
|
|
— |
|
|
|
(2,731 |
) |
| Adjustments to
reconcile loss from continuing operations to net cash provided by
operating activities from continuing operations |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
53,470 |
|
|
|
65,577 |
|
|
|
213,962 |
|
|
|
300,035 |
|
|
Impairment of proved oil and gas properties |
|
— |
|
|
|
411,615 |
|
|
|
576,540 |
|
|
|
1,224,367 |
|
| (Gain)
loss on derivatives, net |
|
19,135 |
|
|
|
(56,665 |
) |
|
|
49,073 |
|
|
|
(99,261 |
) |
| Cash
received for derivative settlements, net |
|
20,549 |
|
|
|
52,387 |
|
|
|
119,369 |
|
|
|
194,296 |
|
| Loss on
extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
38,137 |
|
|
Stock-based compensation expense, net |
|
5,252 |
|
|
|
5,526 |
|
|
|
36,086 |
|
|
|
14,729 |
|
| Deferred
income taxes |
|
— |
|
|
|
(337 |
) |
|
|
— |
|
|
|
(140,875 |
) |
| Non-cash
interest expense, net |
|
1,067 |
|
|
|
725 |
|
|
|
4,172 |
|
|
|
4,289 |
|
| Other,
net |
|
1,326 |
|
|
|
1,155 |
|
|
|
3,753 |
|
|
|
5,709 |
|
| Changes in components
of working capital and other assets and liabilities- |
|
|
|
|
|
|
|
| Accounts
receivable |
|
(14,604 |
) |
|
|
2,386 |
|
|
|
(12,836 |
) |
|
|
29,781 |
|
| Accounts
payable |
|
(9,836 |
) |
|
|
5,498 |
|
|
|
(30,130 |
) |
|
|
(12,617 |
) |
| Accrued
liabilities |
|
16 |
|
|
|
(11,903 |
) |
|
|
(7,938 |
) |
|
|
(17,517 |
) |
| Other
assets and liabilities, net |
|
(675 |
) |
|
|
(777 |
) |
|
|
(3,809 |
) |
|
|
(4,453 |
) |
| Net cash
provided by operating activities from continuing operations |
|
74,921 |
|
|
|
94,516 |
|
|
|
272,768 |
|
|
|
378,735 |
|
| Net cash
used in operating activities from discontinued operations |
|
— |
|
|
|
(121 |
) |
|
|
— |
|
|
|
(1,368 |
) |
|
Net cash provided by operating activities |
|
74,921 |
|
|
|
94,395 |
|
|
|
272,768 |
|
|
|
377,367 |
|
| Cash Flows From
Investing Activities |
|
|
|
|
|
|
|
| Capital expenditures -
oil and gas properties |
|
(134,684 |
) |
|
|
(134,336 |
) |
|
|
(480,929 |
) |
|
|
(675,952 |
) |
| Acquisitions of oil and
gas properties |
|
(153,521 |
) |
|
|
(1,817 |
) |
|
|
(153,521 |
) |
|
|
(1,817 |
) |
| Proceeds from sales of
oil and gas properties, net |
|
233 |
|
|
|
113 |
|
|
|
15,564 |
|
|
|
8,047 |
|
| Other, net |
|
(285 |
) |
|
|
1,736 |
|
|
|
(946 |
) |
|
|
(3,654 |
) |
| Net cash
used in investing activities from continuing operations |
|
(288,257 |
) |
|
|
(134,304 |
) |
|
|
(619,832 |
) |
|
|
(673,376 |
) |
| Net cash
used in investing activities from discontinued operations |
|
— |
|
|
|
(553 |
) |
|
|
— |
|
|
|
(2,678 |
) |
|
Net cash used in investing activities |
|
(288,257 |
) |
|
|
(134,857 |
) |
|
|
(619,832 |
) |
|
|
(676,054 |
) |
| Cash Flows From
Financing Activities |
|
|
|
|
|
|
|
| Issuance of senior
notes |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
650,000 |
|
| Tender and redemption
of senior notes |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(626,681 |
) |
| Payment of deferred
purchase payment |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(150,000 |
) |
| Borrowings under credit
agreement |
|
260,175 |
|
|
|
81,339 |
|
|
|
770,291 |
|
|
|
1,126,860 |
|
| Repayments of
borrowings under credit agreement |
|
(269,175 |
) |
|
|
(237,829 |
) |
|
|
(683,291 |
) |
|
|
(1,126,860 |
) |
| Payments of debt
issuance costs |
|
(180 |
) |
|
|
(755 |
) |
|
|
(1,330 |
) |
|
|
(12,420 |
) |
| Sale of common stock,
net of offering costs |
|
223,739 |
|
|
|
238,842 |
|
|
|
223,739 |
|
|
|
470,158 |
|
| Proceeds from stock
options exercised |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
46 |
|
| Other, net |
|
(264 |
) |
|
|
(221 |
) |
|
|
(1,069 |
) |
|
|
(336 |
) |
| Net cash
provided by financing activities from continuing operations |
|
214,295 |
|
|
|
81,376 |
|
|
|
308,340 |
|
|
|
330,767 |
|
| Net cash
provided by financing activities from discontinued operations |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Net cash provided by financing activities |
|
214,295 |
|
|
|
81,376 |
|
|
|
308,340 |
|
|
|
330,767 |
|
| Net Increase
(Decrease) in Cash and Cash Equivalents |
|
959 |
|
|
|
40,914 |
|
|
|
(38,724 |
) |
|
|
32,080 |
|
| Cash and Cash
Equivalents, Beginning of Period |
|
3,235 |
|
|
|
2,004 |
|
|
|
42,918 |
|
|
|
10,838 |
|
| Cash and Cash
Equivalents, End of Period |
$4,194 |
|
|
$42,918 |
|
|
$4,194 |
|
|
$42,918 |
|
CARRIZO OIL & GAS,
INC.NON-GAAP FINANCIAL
MEASURES(Unaudited)
Reconciliation of Loss From Continuing Operations (GAAP)
to Adjusted Net Income (Non-GAAP)
Adjusted net income is a non-GAAP financial
measure which excludes certain items that are included in loss from
continuing operations, the most directly comparable GAAP financial
measure. Items excluded are those which the Company believes affect
the comparability of operating results and 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 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 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 should not be considered in
isolation or as a substitute for loss from continuing operations or
any other measure of a company’s financial performance or
profitability presented in accordance with GAAP. A reconciliation
of the differences between loss from continuing operations and
adjusted net income is presented below. Because adjusted net income
excludes some, but not all, items that affect loss from continuing
operations and may vary among companies, our calculation of
adjusted net income may not be comparable to similarly titled
measures of other companies.
Reconciliation of Diluted Weighted Average Common Shares
Outstanding (GAAP) to Adjusted Diluted Weighted Average Common
Shares Outstanding (Non-GAAP)
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 loss from continuing operations exists, all
potentially dilutive instruments are anti-dilutive to the loss from
continuing operations per common share and therefore excluded from
the computation of Diluted WASO. The effect of potentially dilutive
instruments are included in the computation of Adjusted Diluted
WASO for purposes of computing diluted adjusted net income per
common share.
| |
Three Months Ended December
31, |
|
Years Ended December 31, |
| |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
| |
(in thousands, except per share
data) |
| Loss From
Continuing Operations (GAAP) |
($779 |
) |
|
($380,671 |
) |
|
($675,474 |
) |
|
($1,157,885 |
) |
| Income tax benefit |
|
— |
|
|
|
419 |
|
|
|
— |
|
|
|
140,875 |
|
| Loss From Continuing
Operations Before Income Taxes |
|
(779 |
) |
|
|
(381,090 |
) |
|
|
(675,474 |
) |
|
|
(1,298,760 |
) |
| (Gain)
loss on derivatives, net |
|
19,135 |
|
|
|
(56,665 |
) |
|
|
49,073 |
|
|
|
(99,261 |
) |
| Cash
received for derivative settlements, net |
|
20,549 |
|
|
|
52,387 |
|
|
|
119,369 |
|
|
|
194,296 |
|
| Non-cash
general and administrative expense, net |
|
5,025 |
|
|
|
2,018 |
|
|
|
36,009 |
|
|
|
15,794 |
|
|
Impairment of proved oil and gas properties |
|
— |
|
|
|
411,615 |
|
|
|
576,540 |
|
|
|
1,224,367 |
|
| Loss on
extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
38,137 |
|
| Other
expense, net |
|
228 |
|
|
|
487 |
|
|
|
618 |
|
|
|
11,276 |
|
| Adjusted income before
income taxes |
|
44,158 |
|
|
|
28,752 |
|
|
|
106,135 |
|
|
|
85,849 |
|
| Adjusted income tax
expense (1) |
|
(15,720 |
) |
|
|
(10,263 |
) |
|
|
(37,784 |
) |
|
|
(30,648 |
) |
| Adjusted Net
Income (Non-GAAP) |
$28,438 |
|
|
$18,489 |
|
|
$68,351 |
|
|
$55,201 |
|
| |
|
|
|
|
|
|
|
| Loss From
Continuing Operations Per Common Share - Diluted
(GAAP) |
($0.01 |
) |
|
($6.73 |
) |
|
($11.27 |
) |
|
($22.50 |
) |
| Effect of change from
diluted WASO to adjusted diluted WASO |
|
— |
|
|
|
(0.07 |
) |
|
|
(0.12 |
) |
|
|
(0.27 |
) |
| Income tax benefit |
|
— |
|
|
|
0.01 |
|
|
|
— |
|
|
|
2.70 |
|
| Loss From Continuing
Operations Before Income Taxes |
|
(0.01 |
) |
|
|
(6.67 |
) |
|
|
(11.15 |
) |
|
|
(24.93 |
) |
| (Gain)
loss on derivatives, net |
|
0.30 |
|
|
|
(0.99 |
) |
|
|
0.81 |
|
|
|
(1.90 |
) |
| Cash
received for derivative settlements, net |
|
0.32 |
|
|
|
0.91 |
|
|
|
1.97 |
|
|
|
3.73 |
|
| Non-cash
general and administrative expense, net |
|
0.08 |
|
|
|
0.03 |
|
|
|
0.60 |
|
|
|
0.30 |
|
|
Impairment of proved oil and gas properties |
|
— |
|
|
|
7.21 |
|
|
|
9.51 |
|
|
|
23.50 |
|
| Loss on
extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
0.73 |
|
| Other
expense, net |
|
— |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
0.22 |
|
| Adjusted income before
income taxes |
|
0.69 |
|
|
|
0.50 |
|
|
|
1.75 |
|
|
|
1.65 |
|
| Adjusted income tax
expense (1) |
|
(0.25 |
) |
|
|
(0.18 |
) |
|
|
(0.62 |
) |
|
|
(0.59 |
) |
| Adjusted Net
Income Per Common Share - Diluted (Non-GAAP) |
|
$0.44 |
|
|
$ |
0.32 |
|
|
$ |
1.13 |
|
|
$ |
1.06 |
|
| |
|
|
|
|
|
|
|
| Diluted WASO
(GAAP) |
|
63,587 |
|
|
|
56,544 |
|
|
|
59,932 |
|
|
|
51,457 |
|
| Effect of potentially
dilutive instruments |
|
717 |
|
|
|
550 |
|
|
|
668 |
|
|
|
648 |
|
| Adjusted
Diluted WASO (Non-GAAP) |
|
64,304 |
|
|
|
57,094 |
|
|
|
60,600 |
|
|
|
52,105 |
|
___________
(1) Adjusted income tax expense is calculated by applying the
Company’s effective income tax rates applicable to the adjusted
income before income taxes which were 35.6% and 35.7% for the years
ended December 31, 2016 and 2015, respectively.
CARRIZO OIL & GAS,
INC.NON-GAAP FINANCIAL
MEASURES(Unaudited)
Reconciliation of Loss From Continuing Operations (GAAP)
to Adjusted EBITDA (Non-GAAP) to Net Cash Provided by Operating
Activities From Continuing Operations (GAAP)
Adjusted EBITDA is a non-GAAP financial measure
which excludes certain items that are included in loss from
continuing operations, the most directly comparable GAAP financial
measure. Items excluded are interest expense, depreciation,
depletion and amortization 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 items that
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 loss from continuing operations,
net cash provided by operating activities from continuing
operations, or any other measure of a company's profitability, or
liquidity measures presented in accordance with GAAP. A
reconciliation of loss from continuing operations to adjusted
EBITDA to net cash provided by operating activities from continuing
operations is presented below. Because adjusted EBITDA excludes
some, but not all, items that affect loss from continuing
operations, our calculations of adjusted EBITDA may not be
comparable to similarly titled measures of other companies.
Reconciliation of Net Cash Provided by Operating
Activities From Continuing Operations (GAAP) to Discretionary Cash
Flows (Non-GAAP)
Discretionary cash flows is a non-GAAP financial
measure which excludes certain items that are included in net cash
provided by operating activities from continuing operations, the
most directly comparable GAAP financial measure. Items excluded are
changes in 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 is presented because
management believes it provides useful additional information to
investors for analysis of the Company’s ability to generate cash to
internally 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 from continuing operations 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 from continuing operations 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 from continuing operations 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, |
| |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
| |
(in thousands) |
| Loss From
Continuing Operations (GAAP) |
($779 |
) |
|
($380,671 |
) |
|
($675,474 |
) |
|
($1,157,885 |
) |
| Income tax benefit |
|
— |
|
|
|
419 |
|
|
|
— |
|
|
|
140,875 |
|
| Loss From Continuing
Operations Before Income Taxes |
|
(779 |
) |
|
|
(381,090 |
) |
|
|
(675,474 |
) |
|
|
(1,298,760 |
) |
|
Depreciation, depletion and amortization |
|
53,470 |
|
|
|
65,577 |
|
|
|
213,962 |
|
|
|
300,035 |
|
| Interest
expense, net |
|
20,490 |
|
|
|
17,792 |
|
|
|
79,403 |
|
|
|
69,195 |
|
| (Gain)
loss on derivatives, net |
|
19,135 |
|
|
|
(56,665 |
) |
|
|
49,073 |
|
|
|
(99,261 |
) |
| Cash
received for derivative settlements, net |
|
20,549 |
|
|
|
52,387 |
|
|
|
119,369 |
|
|
|
194,296 |
|
| Non-cash
general and administrative expense, net |
|
5,025 |
|
|
|
2,018 |
|
|
|
36,009 |
|
|
|
15,794 |
|
|
Impairment of proved oil and gas properties |
|
— |
|
|
|
411,615 |
|
|
|
576,540 |
|
|
|
1,224,367 |
|
| Loss on
extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
38,137 |
|
| Other
expense, net |
|
228 |
|
|
|
487 |
|
|
|
618 |
|
|
|
11,276 |
|
| Adjusted EBITDA
(Non-GAAP) |
$118,118 |
|
|
$112,121 |
|
|
$399,500 |
|
|
$455,079 |
|
| Interest
expense, net |
|
(20,490 |
) |
|
|
(17,792 |
) |
|
|
(79,403 |
) |
|
|
(69,195 |
) |
| Non-cash
interest expense, net |
|
1,067 |
|
|
|
725 |
|
|
|
4,172 |
|
|
|
4,289 |
|
| Other
cash and non-cash adjustments, net |
|
999 |
|
|
|
26 |
|
|
|
2,986 |
|
|
|
(4,658 |
) |
| Discretionary
Cash Flows (Non-GAAP) |
$99,694 |
|
|
$95,080 |
|
|
$327,255 |
|
|
$385,515 |
|
| Changes
in components of working capital and other |
|
(24,773 |
) |
|
|
(564 |
) |
|
|
(54,487 |
) |
|
|
(6,780 |
) |
| Net Cash
Provided By Operating Activities
From Continuing Operations
(GAAP) |
$74,921 |
|
|
$94,516 |
|
|
$272,768 |
|
|
$378,735 |
|
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, 2016 |
| |
|
(in millions) |
| Standardized
measure of discounted future net cash flows (GAAP) |
|
$1,303.4 |
|
| Add: present value of
future income taxes discounted at 10% per annum (1) |
|
|
— |
|
| PV-10
(Non-GAAP) |
|
$1,303.4 |
|
____________
(1) Future income taxes in the calculation of
the standardized measure of discounted future net cash flows were
zero as of December 31, 2016, as the historical tax basis of proved
oil and gas properties, net operating loss carryforwards, and
future tax deductions exceeded the undiscounted future net cash
flows before income taxes of the Company's proved oil and gas
reserves as of December 31, 2016.
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. Drill-bit reserve replacement excluding
price-related revisions is defined as the sum of proved reserve
extensions and discoveries and revisions of previous estimates
other than price-related revisions 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. Drill-bit F&D cost excluding price-related revisions
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 other than price-related revisions.
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 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, |
| |
|
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
| Total
production volumes - |
|
|
|
|
|
|
|
|
| Crude oil
(MBbls) |
|
|
2,643 |
|
|
|
2,295 |
|
|
|
9,423 |
|
|
|
8,415 |
|
| NGLs
(MBbls) |
|
|
464 |
|
|
|
371 |
|
|
|
1,788 |
|
|
|
1,352 |
|
| Natural
gas (MMcf) |
|
|
6,072 |
|
|
|
6,174 |
|
|
|
25,574 |
|
|
|
21,812 |
|
|
Total barrels of oil equivalent (MBoe) |
|
|
4,119 |
|
|
|
3,695 |
|
|
|
15,473 |
|
|
|
13,402 |
|
| |
|
|
|
|
|
|
|
|
| Daily
production volumes by product - |
|
|
|
|
|
|
|
|
| Crude oil
(Bbls/d) |
|
|
28,727 |
|
|
|
24,942 |
|
|
|
25,745 |
|
|
|
23,054 |
|
| NGLs
(Bbls/d) |
|
|
5,048 |
|
|
|
4,032 |
|
|
|
4,885 |
|
|
|
3,705 |
|
| Natural
gas (Mcf/d) |
|
|
65,999 |
|
|
|
67,110 |
|
|
|
69,873 |
|
|
|
59,758 |
|
|
Total barrels of oil equivalent (Boe/d) |
|
|
44,775 |
|
|
|
40,159 |
|
|
|
42,276 |
|
|
|
36,719 |
|
| |
|
|
|
|
|
|
|
|
| Daily
production volumes by region (Boe/d) - |
|
|
|
|
|
|
|
|
| Eagle
Ford |
|
|
32,339 |
|
|
|
29,058 |
|
|
|
30,664 |
|
|
|
26,377 |
|
| Delaware
Basin |
|
|
2,469 |
|
|
|
250 |
|
|
|
1,115 |
|
|
|
104 |
|
|
Niobrara |
|
|
3,190 |
|
|
|
2,642 |
|
|
|
2,931 |
|
|
|
2,957 |
|
|
Marcellus |
|
|
5,965 |
|
|
|
6,934 |
|
|
|
6,329 |
|
|
|
5,850 |
|
| Utica and
other |
|
|
812 |
|
|
|
1,275 |
|
|
|
1,237 |
|
|
|
1,431 |
|
|
Total barrels of oil equivalent (Boe/d) |
|
|
44,775 |
|
|
|
40,159 |
|
|
|
42,276 |
|
|
|
36,719 |
|
| |
|
|
|
|
|
|
|
|
| Realized prices
- |
|
|
|
|
|
|
|
|
| Crude oil
($ per Bbl) |
|
$46.66 |
|
|
$37.71 |
|
|
$40.12 |
|
|
$44.69 |
|
|
Crude oil ($ per Bbl) - including cash received/paid for
derivative settlements, net |
|
$54.43 |
|
|
$58.11 |
|
|
$52.80 |
|
|
$65.67 |
|
| NGLs ($
per Bbl) |
|
$15.75 |
|
|
$10.80 |
|
|
$12.54 |
|
|
$11.54 |
|
| Natural
gas ($ per Mcf) |
|
$2.18 |
|
|
$1.44 |
|
|
$1.69 |
|
|
$1.72 |
|
|
Natural gas ($ per Mcf) - including cash received/paid for
derivative settlements, net |
|
$2.18 |
|
|
$2.34 |
|
|
$1.68 |
|
|
$2.53 |
|
| CARRIZO OIL & GAS, INC. |
| COMMODITY DERIVATIVE CONTRACTS - AS OF
FEBRUARY 21, 2017 |
| (Unaudited) |
| |
|
|
|
|
|
|
|
|
| Crude Oil Derivative Contracts |
| |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
Weighted Average |
|
Weighted Average |
| |
|
|
|
Volume |
|
Floor Price |
|
Ceiling Price |
|
Period |
|
Type of Contract |
|
(in Bbls/d) |
|
($/Bbl) |
|
($/Bbl) |
| Q1 2017 |
|
Fixed Price Swaps |
|
12,000 |
|
$50.13 |
|
|
| |
|
|
|
|
|
|
|
|
| Q2 2017 |
|
Fixed Price Swaps |
|
12,000 |
|
$50.13 |
|
|
| |
|
|
|
|
|
|
|
|
| Q3 2017 |
|
Fixed Price Swaps |
|
6,000 |
|
$54.15 |
|
|
| |
|
|
|
|
|
|
|
|
| Q4 2017 |
|
Fixed Price Swaps |
|
3,000 |
|
$55.01 |
|
|
| |
|
|
|
|
|
|
|
|
| FY 2018 |
|
Net Sold Call
Options |
|
3,388 |
|
|
|
$63.98 |
| |
|
|
|
|
|
|
|
|
| FY 2019 |
|
Net Sold Call
Options |
|
3,875 |
|
|
|
$65.98 |
| |
|
|
|
|
|
|
|
|
| FY 2020 |
|
Net Sold Call
Options |
|
4,575 |
|
|
|
$67.95 |
| Natural Gas Derivative Contracts |
| |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
Weighted Average |
|
Weighted Average |
| |
|
|
|
Volume |
|
Floor Price |
|
Ceiling Price |
|
Period |
|
Type of Contract |
|
(in MMBtu/d) |
|
($/MMBtu) |
|
($/MMBtu) |
| FY 2017 |
|
Fixed Price Swaps |
|
20,000 |
|
$3.30 |
|
|
| |
|
Sold Call Options |
|
33,000 |
|
|
|
$3.00 |
| |
|
|
|
|
|
|
|
|
| FY 2018 |
|
Sold Call Options |
|
33,000 |
|
|
|
$3.25 |
| |
|
|
|
|
|
|
|
|
| FY 2019 |
|
Sold Call Options |
|
33,000 |
|
|
|
$3.25 |
| |
|
|
|
|
|
|
|
|
| FY 2020 |
|
Sold Call Options |
|
33,000 |
|
|
|
$3.50 |
| CARRIZO OIL & GAS, INC. |
| FIRST QUARTER AND FULL YEAR 2017 GUIDANCE
SUMMARY |
| |
|
|
|
|
|
| |
|
|
First Quarter 2017 |
|
Full Year 2017 |
|
Daily Production Volumes - |
|
|
|
|
| |
Crude oil
(Bbls/d) |
|
27,700
- 28,100 |
|
31,400
- 31,900 |
| |
NGLs
(Bbls/d) |
|
4,700
- 4,900 |
|
5,600
- 5,900 |
| |
Natural
gas (Mcf/d) |
|
72,000
- 76,000 |
|
69,000
- 73,000 |
| |
Total
(Boe/d) |
|
44,400
- 45,667 |
|
48,500
- 49,967 |
| |
|
|
|
|
|
|
Unhedged Commodity Price Realizations - |
|
|
|
|
| |
Crude oil
(% of NYMEX oil) |
|
93.0%
- 95.0% |
|
N/A |
| |
NGLs (%
of NYMEX oil) |
|
31.0%
- 33.0% |
|
N/A |
| |
Natural
gas (% of NYMEX gas) |
|
68.0%
- 73.0% |
|
N/A |
| |
|
|
|
|
|
| Cash
received for derivative settlements, net (in millions) |
|
$0.0 -
$2.0 |
|
N/A |
| |
|
|
|
|
|
|
Costs and Expenses - |
|
|
|
|
| |
Lease
operating ($/Boe) |
|
$6.75
- $7.25 |
|
$6.75
- $7.50 |
| |
Production taxes (% of total revenues) |
|
4.25%
- 4.50% |
|
4.25%
- 4.75% |
| |
Ad
valorem taxes (in millions) |
|
$2.7 -
$3.2 |
|
$11.0
- $13.0 |
| |
Cash
general and administrative, net (in millions) |
|
$16.5
- $20.5 |
|
$47.0
- $51.0 |
| |
DD&A
($/Boe) |
|
$12.75
- $13.75 |
|
$13.50
- $14.50 |
| |
Interest
expense, net (in millions) |
|
$20.5
- $21.5 |
|
N/A |
| |
|
|
|
|
|
|
Capitalized Items - |
|
|
|
|
| |
Drilling
and completion capital expenditures (in millions) |
|
N/A |
|
$530.0
- $550.0 |
| |
Capitalized interest (in millions) |
|
$3.5 -
$4.0 |
|
N/A |
Contact:
Jeffrey P. Hayden, CFA, VP - Investor Relations
(713) 328-1044
Kim Pinyopusarerk, Manager - Investor Relations
(713) 358-6430
Carrizo Oil and Gas (NASDAQ:CRZO)
Historical Stock Chart
From Mar 2024 to Apr 2024
Carrizo Oil and Gas (NASDAQ:CRZO)
Historical Stock Chart
From Apr 2023 to Apr 2024
