Venoco, Inc. (NYSE: VQ) today reported financial and operational
results for the fourth quarter and full-year 2011. The company
reported net income for the year of $62 million on total revenues
of $329 million.
Adjusted Earnings, which adjusts for unrealized derivative gains
and losses and certain one-time charges, were $43 million for the
year. Adjusted EBITDA was $219 million in 2011, up slightly from
$218 million in 2010. Please see the end of this release for
definitions of Adjusted Earnings and Adjusted EBITDA and a
reconciliation of those measures to net income/loss.
Highlights include the following:
- Production of 6.4 million barrels of oil equivalent (MMBOE) for
the year, or 17,612 BOE per day (BOE/d).
- Proved reserves of 95.9 MMBOE as of December 31, 2011, up
significantly over year-end 2010 proved reserves. Reserve
replacement of 265% at an all-in F&D cost of $14.35 per
BOE.
- Ellwood pipeline completed ahead of schedule and is now in
service. Transportation savings and higher price realization
improve field economics.
"In 2011 we transitioned our focus from the Sacramento Basin
toward our oily, Southern California legacy assets, while
continuing to delineate our Sevier field and other portions of the
onshore Monterey shale acreage," said Tim Marquez, Venoco's
Chairman and CEO. "As a result of very strong California oil prices
throughout 2011, we realized average oil prices of $91 per barrel
for the year, up more than $22 per barrel from the average in 2010
even though only half of our oil production was sold on California
postings. As of April 1, 2012, the other 50% of our oil will be
sold based on California postings, which we expect to exceed NYMEX
pricing in 2012 based on current differentials."
Fourth Quarter and Full-Year
Production
Production in the fourth quarter of 2011 of 17,810 BOE/d was up
over 3% from the third quarter of 2011 as well as up 3% from the
fourth quarter of 2010.
"We recovered from the production delays in the third quarter to
finish with a solid fourth quarter," commented Mr. Marquez. "We
have had a good start in the new year as we concentrate our efforts
on our oily assets. With natural gas prices expected to remain low
in 2012, our plan is to minimize expenditures in the Sacramento
Basin. As a result, we expect to see production volumes from the
Basin trend down throughout 2012. However, our increased activity
in the legacy Southern California assets, where we expect to see a
15-20% increase in oil volumes in 2012 compared to 2011, is
expected to largely offset the decline in natural gas production.
While we are forecasting basically flat production in 2012 compared
to 2011, we expect the increase in our oil mix to result in
significant revenue growth. In addition, we believe we've been
conservative forecasting production from the Sevier field, so
additional successful drilling in the field could further increase
our oil over natural gas mix," Mr. Marquez added.
The following table details the company's daily production by
region (BOE(1)/d):
----------------------------------------------------------------------------
Full Year
----------------------------------------------------------------------------
Region 4Q 2010 3Q 2011 4Q 2011 2010 2011
----------------------------------------------------------------------------
Sacramento Basin 10,163 10,337 10,635 10,033 10,446
----------------------------------------------------------------------------
Southern California 7,165 6,928 7,175 7,745 7,166
----------------------------------------------------------------------------
Texas(2) - - - 463 -
----------------------------------------------------------------------------
Total 17,328 17,265 17,810 18,241 17,612
----------------------------------------------------------------------------
(1) Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf
of natural gas to one barrel of crude oil, condensate or natural gas
liquids.
(2) Venoco sold its remaining producing assets in Texas in the first half of
2010.
----------------------------------------------------------------------------
Fourth Quarter and Full-Year Costs
Venoco's fourth quarter 2011 lease operating expenses of $13.87
per BOE were down from $18.06 per BOE in the third quarter. The
third quarter expenses were unusually high on a per BOE basis due
primarily to two high-cost electric submersible pump replacements
in the quarter and a resulting reduction in production levels. The
company's full-year 2011 lease operating expenses of $14.64 per BOE
were below the company's revised guidance of $15.00 per BOE.
Quarter Ended Year Ended
-------------------------- -----------------
UNAUDITED (per BOE) 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
-------- -------- -------- -------- --------
Lease Operating Expenses $ 12.61 $ 18.06 $ 13.87 $ 12.65 $ 14.64
Production/Property Taxes 0.87 1.13 0.97 1.01 0.99
DD&A Expense 12.74 12.85 13.43 11.79 13.35
G&A Expense (1) 4.93 4.43 5.46 4.78 4.96
(1) Net of amounts capitalized and excluding stock-based compensation costs,
costs related to the special committee's review of the going-private
proposal from the company's Chairman & CEO and other costs associated
with the sale of Texas assets.See the end of this release for a
reconciliation of G&A per BOE.
Capital Investment 2011
Venoco's 2011 capital expenditures for exploration, development
and other spending were $255 million, including $185 million for
drilling and rework activities, $20 million for facilities, and the
remaining $50 million for land, seismic and capitalized
G&A.
In 2011 the company spent $74 million or 29% of its capital
expenditures in the Sacramento Basin. The company spud 40 wells,
performed 237 recompletions, and hydraulically fractured 21 wells
in the basin. In early 2011 the company drilled a discovery well on
an anomaly which was identified using 3D seismic data that was
acquired with leasehold in 2009. The discovery well's net average
production in 2011 was 2.3 million cubic feet per day and it
extended the boundaries of the Grimes field. Additional wells were
drilled in 2011 along this extension area which, combined with the
discovery well, exited the year at a net rate of 8.3 million cubic
feet per day. Additional opportunities have been identified in the
area, but will not be pursued at current natural gas prices. In
2012 the company plans to reduce activity levels in the basin as a
result of very low natural gas prices.
The company's 2012 capital expenditure budget remains at $255
million. However, the budget has been reallocated to focus
resources on oily projects. The company's budget for the Sacramento
Basin was reduced from $45 million to $32 million and includes 5
wells, 180 recompletions, and 7 hydraulic fractures. The company
expects the decreased activity levels in the basin in 2012 compared
to 2011 to result in a decline in average daily production there
throughout the year.
The company's Southern California legacy fields accounted for
$67 million or 26% of its 2011 capital expenditures. Five wells
were spud at the West Montalvo field, one to an onshore bottom-hole
and four to the offshore. The company also performed five
recompletions in the field during 2011. At the Sockeye field the
company redrilled two idle wells to new locations targeting the
Monterey shale formation. One was a completion targeting the M4
portion of the Monterey, the other a horizontal well into the M2
portion of the Monterey. At the South Ellwood field, the company
completed facilities work on Platform Holly in preparation for
drilling activities. The company also permitted and began
construction of a new common-carrier pipeline, which was completed
and put in service in January 2012. As a result of receiving the
approvals to construct the pipeline in 2011, the company was able
to add approximately 8 million BOE of reserves at year-end 2011,
which is reflected as a component of revisions in the reserve table
below. In addition, with the pipeline now in service, the barge
contract will terminate by June 1, 2012 and the company will
realize a reduction in transportation costs for South Ellwood
crude. The company also entered into a new sales contract for the
crude oil that is expected to add $5 to $10 per barrel in 2012 to
the company's realizations from the field.
The company's 2012 capital expenditure budget for legacy
Southern California properties was increased from $110 million to
$123 million and includes plans to drill seven wells at West
Montalvo, one of which was spud in the fourth quarter of 2011. Two
more wells were spud in the first quarter of 2012 with a third well
scheduled to spud late in the quarter. The company plans to drill
three wells in 2012 at the Sockeye field and four wells at the
South Ellwood field. The company expects production levels from its
Southern California legacy fields to grow 15-20% in 2012 compared
with 2011.
The company increased its capital expenditures on its onshore
Monterey shale play for the second year in a row, spending
approximately $113 million or 44% of its 2011 capital expenditures.
The company spud 12 wells during 2011 including nine vertical and
three horizontal wells. Six of the verticals were in the Sevier
field including four that spud in the fourth quarter. The company
completed the second half of the joint 3D seismic shoot over its
acreage in the San Joaquin Basin during 2011.
The company's 2012 capital expenditure budget for the onshore
Monterey shale development is $100 million, with an emphasis on
delineation and production at the Sevier field where the company
plans to spud 15 to 20 wells. To date, the company has not seen
material levels of production or reserves from the program. The
company does believe it will see production resulting from the
drilling and testing efforts at Sevier begun in 2011 and which are
continuing into 2012. The company also plans to acquire seismic
data at the Sevier and Salinas fields, and to recomplete several
wells located in its greater San Joaquin leasehold.
"In the second quarter of 2011, we decided to focus our Monterey
drilling on vertical delineation wells in the Sevier field. Each
well has confirmed our geologic model and, in some cases, expanded
our view of the structure. We have been methodical with our one-rig
delineation program, but the data -- from cuttings, logs, and
testing -- takes months to gather," commented Mr. Marquez. "We
believe we are approaching the point where we can streamline
completions, minimize zone-by-zone testing and get wells from spud
to sales much more rapidly and efficiently in 2012."
Reserves Review
The company's year-end 2011 total proved reserves were 95.9
million BOE, compared to year-end 2010 reserves of 85.1 million
BOE. After adjusting for 2011 production of 6.4 million BOE, the
company added reserves of 17.2 million BOE, including revisions,
extensions and discoveries, which were primarily related to
permitting the crude oil pipeline at South Ellwood, oil price
increase from year-end 2010, and drilling in new areas of the
Sacramento Basin as well as performance in the Basin and at the
Sockeye field.
"We are very pleased with the 17 million BOE of reserve adds
this year that resulted from our capital expenditure program,
strong California oil prices, new oil sales agreements and
permitting the new pipeline to service the South Ellwood field,"
said Mr. Marquez. "A valuable asset that currently has minimal
proven reserves is our 22.3% reversionary working interest in the
Hastings field. After a year of flooding the field with CO2,
Denbury Resources returned the field to production in mid-January.
We have approximately 16 million barrels of probable reserves
associated with the reversionary interest -- a portion of which we
expect to be converted to proved once the field responds to the
flood."
The company's 2011 rollforward of proved reserves is as
follows:
2011 Reserve Rollforward MBOE(1)
---------------
Beginning of the year reserves 85,098
Revisions of previous estimates 849
Extensions and discoveries 16,298
Purchases of reserves in place 67
Production (6,428)
Sales of reserves in place -
---------------
End of year reserves 95,884
===============
Proved developed reserves:
Beginning of year 42,758
End of year 48,765
(1) Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf
of natural gas to one barrel of crude oil, condensate or natural gas
liquids.
The company's all-in finding and development (F&D) costs in
2011 were $14.35 per BOE and its 3-year and 5-year all-in F&D
costs were $19.28 and $24.67 per BOE, respectively. Adjusting for
capital related to the Monterey Shale play and the Hastings field
before its sale in early 2009, the company estimates its 3-year and
5-year F&D costs would have been approximately $13.76 and
$17.92 per BOE, respectively.
The $1.81 billion pre-tax PV-10 value of the company's 95.9
MMBOE of reserves is based on SEC benchmark pricing of $96.19 per
barrel of oil and $4.12 per MMBTU for gas. Using the December 31,
2011 NYMEX 5-year strip pricing, the company's estimate of reserves
is 96.8 MMBOE and the pre-tax PV-10 value is $1.76 billion. See the
end of this release for a reconciliation of PV-10 to a standardized
measure.
The following table details the company's reserve categories for
the last three years and PV-10 for 2010 and 2011:
Net Proved Reserves (end of period) 2009PF(1) 2010 2011
---------- ----------- -----------
Oil (MBbls)
Developed 25,750 22,270 25,131
Undeveloped 21,758 20,301 22,282
---------- ----------- -----------
Total 47,508 42,571 47,413
Natural Gas (MMcf)
Developed 120,052 122,928 141,806
Undeveloped 142,314 132,235 149,018
---------- ----------- -----------
Total 262,366 255,163 290,824
---------- ----------- -----------
Total Proved Reserves (MBOE)(2) 91,236 85,098 95,884
========== =========== ===========
PV-10 ($000)
Developed $ 575,152 $ 990,303
Undeveloped 553,544 816,198
----------- -----------
Total $ 1,128,696 $ 1,806,501
=========== ===========
(1) Pro forma for the sale of the company's Texas assets in the first half
of 2010.
(2) Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf
of natural gas to one barrel of crude oil, condensate or natural gas
liquids.
2012 Guidance
The following summarizes the company's 2012 guidance:
- Production: 17,750 - 18,250 BOE/d
- Capital Budget: $255 million
- Lease Operating Expenses: $15.00 - $15.50 per BOE
- General & Administrative Expenses: $5.25 - $5.50 per
BOE
- Production & Property Taxes: $1.00 - $1.10 per BOE
- DD&A: $15.00 - $15.50 per BOE
Special Committee Process
On August 26, 2011, the company's board of directors received a
proposal from Mr. Marquez, Venoco's Chairman and CEO, to acquire
all of the outstanding shares of common stock of Venoco of which he
is not the beneficial owner for $12.50 per share in cash. Mr.
Marquez is the beneficial owner of approximately 50.3% of Venoco's
common stock. On January 16, 2012, the company announced that it
entered into a definitive merger agreement under which Mr. Marquez
will, through a wholly owned affiliate, acquire all of the
outstanding shares of Venoco he does not already own.
Completion of the transaction is subject to certain closing
conditions, including procurement of financing. The merger
agreement also contains a non-waivable condition that a majority of
the outstanding shares of Venoco not owned by Mr. Marquez and his
affiliates, or by any director, officer or employee of Venoco or
its subsidiaries, vote in favor of the adoption of the merger
agreement. Shareholders are cautioned that there can be no
assurance that the company will complete the merger.
Earnings Conference Call
Venoco will host a conference call to discuss results today,
Thursday, February 16, 2012 at 11:00 a.m. Eastern time (9 a.m.
Mountain). The conference call will be webcast and those wanting to
listen may do so by using a link on the Investor Relations page of
the company's website at http://www.venocoinc.com. Those wanting to
participate in the Q & A portion can call (800) 706-7748 and
use conference code 51448500. International participants can call
(617) 614-3473 and use the same conference code.
A replay of the conference call will be available for one week
by calling (888) 286-8010 or, for international callers, (617)
801-6888, and using passcode 24271802. The replay will also be
available on the Venoco website for 30 days.
About the Company
Venoco is an independent energy company primarily engaged in the
acquisition, exploitation and development of oil and natural gas
properties primarily in California. Venoco operates three offshore
platforms in the Santa Barbara Channel, has non-operated interests
in three other platforms, operates three onshore properties in
Southern California, and has extensive operations in Northern
California's Sacramento Basin.
Forward-looking Statements
Statements made in this news release relating to Venoco's future
production, expenses, revenue, price realizations (including in
relation to benchmark prices), oil/gas production mix, reserves,
capital expenditures and development projects, and all other
statements except statements of historical fact, are
forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange
Act of 1934. These statements are based on assumptions and
estimates that management believes are reasonable based on
currently available information; however, management's assumptions
and the company's future performance are both subject to a wide
range of business risks and uncertainties and there is no assurance
that these goals and projections can or will be met. Any number of
factors could cause actual results to differ materially from those
in the forward-looking statements, including, but not limited to,
the timing and extent of changes in oil and gas prices, the timing
and results of drilling and other development activities, the
availability and cost of obtaining drilling equipment and technical
personnel, risks associated with the availability of acceptable
transportation arrangements and the possibility of unanticipated
operational problems, delays in completing production, treatment
and transportation facilities, higher than expected production
costs and other expenses, and pipeline curtailments by third
parties. The company's activities with respect to the onshore
Monterey Shale and other projects are subject to numerous
operating, geological and other risks and may not be successful.
The company's results in the onshore Monterey Shale will be subject
to greater risks than in areas where it has more data and drilling
and production experience. Results from the company's onshore
Monterey Shale project will depend on, among other things, its
ability to identify productive intervals and drilling and
completion techniques necessary to achieve commercial production
from those intervals. The closing of the merger agreement with Mr.
Marquez is subject to a number of conditions, including a financing
condition and a non-waivable condition that a majority of the
outstanding shares of Venoco not owned by Mr. Marquez and his
affiliates or by any director, officer or employee of Venoco or its
subsidiaries vote in favor of the adoption of the merger agreement,
and those conditions may not be satisfied. All forward-looking
statements are made only as of the date hereof and the company
undertakes no obligation to update any such statement. Further
information on risks and uncertainties that may affect the
Company's operations and financial performance, and the
forward-looking statements made herein, is available in the
company's filings with the Securities and Exchange Commission,
which are incorporated by this reference as though fully set forth
herein.
References to reserve estimates other than proved are by their
nature more uncertain than estimates of proved reserves, and are
subject to substantially greater risk of not actually being
realized by the company.
OIL AND NATURAL GAS PRODUCTION AND PRICES
Quarter Ended Quarter Ended
-------------------------- --------------------------
% %
UNAUDITED 9/30/11 12/31/11 Change 12/31/10 12/31/11 Change
-------- -------- ------ -------- -------- ------
Production Volume:
Oil (MBbls) (1) 594 620 4% 629 620 -1%
Natural Gas (MMcf) 5,966 6,111 2% 5,791 6,111 6%
-------- -------- ------ -------- -------- ------
MBOE 1,588 1,639 3% 1,594 1,639 3%
======== ======== ====== ======== ======== ======
Daily Average
Production Volume:
Oil (Bbls/d) 6,457 6,739 4% 6,837 6,739 -1%
Natural Gas (Mcf/d) 64,848 66,424 2% 62,946 66,424 6%
-------- -------- ------ -------- -------- ------
BOE/d 17,265 17,810 3% 17,328 17,810 3%
======== ======== ====== ======== ======== ======
Oil Price per Barrel
Produced (in
dollars):
Realized price
before hedging $ 87.24 $ 93.79 8% $ 74.58 $ 93.79 26%
Realized hedging
gain (loss) (5.01) (1.35) -73% (3.02) (1.35) -55%
-------- -------- ------ -------- -------- ------
Net realized price $ 82.23 $ 92.44 12% $ 71.56 $ 92.44 29%
======== ======== ====== ======== ======== ======
Natural Gas Price
per Mcf (in
dollars):
Realized price
before hedging $ 4.18 $ 3.60 -14% $ 3.96 $ 3.60 -9%
Realized hedging
gain (loss) 0.93 1.29 39% 2.15 1.29 -40%
-------- -------- ------ -------- -------- ------
Net realized price $ 5.11 $ 4.89 -4% $ 6.11 $ 4.89 -20%
======== ======== ====== ======== ======== ======
Expense per BOE (in
dollars):
Lease operating
expenses $ 18.06 $ 13.87 -23% $ 12.61 $ 13.87 10%
Production and
property taxes $ 1.13 $ 0.97 -14% $ 0.87 $ 0.97 11%
Transportation
expenses $ 1.49 $ 1.42 -5% $ 1.64 $ 1.42 -13%
Depreciation,
depletion and
amortization $ 12.85 $ 13.43 5% $ 12.74 $ 13.43 5%
General and
administrative (2) $ 5.82 $ 6.89 18% $ 5.72 $ 6.89 20%
Interest expense $ 10.08 $ 10.03 0% $ 6.30 $ 10.03 59%
Year Ended
--------------------------
%
UNAUDITED 12/31/10 12/31/11 Change
-------- -------- ------
Production Volume:
Oil (MBbls) (1) 2,792 2,441 -13%
Natural Gas (MMcf) 23,196 23,923 3%
-------- -------- ------
MBOE 6,658 6,428 -3%
======== ======== ======
Daily Average
Production Volume:
Oil (Bbls/d) 7,649 6,688 -13%
Natural Gas (Mcf/d) 63,551 65,542 3%
-------- -------- ------
BOE/d 18,241 17,612 -3%
======== ======== ======
Oil Price per Barrel
Produced (in
dollars):
Realized price
before hedging $ 68.86 $ 91.00 32%
Realized hedging
gain (loss) (1.77) (2.48) 40%
-------- -------- ------
Net realized price $ 67.09 $ 88.52 32%
======== ======== ======
Natural Gas Price
per Mcf (in
dollars):
Realized price
before hedging $ 4.34 $ 4.02 -7%
Realized hedging
gain (loss) 1.70 1.03 -39%
-------- -------- ------
Net realized price $ 6.04 $ 5.05 -16%
======== ======== ======
Expense per BOE (in
dollars):
Lease operating
expenses $ 12.65 $ 14.64 16%
Production and
property taxes $ 1.01 $ 0.99 -2%
Transportation
expenses $ 1.37 $ 1.45 6%
Depreciation,
depletion and
amortization $ 11.79 $ 13.35 13%
General and
administrative (2) $ 5.64 $ 6.10 8%
Interest expense $ 6.10 $ 9.51 56%
(1) Amounts shown are oil production volumes for offshore properties and
sales volumes for onshore properties (differences between onshore production
and sales volumes are minimal). Revenue accruals are adjusted for actual
sales volumes since offshore oil inventories can vary significantly from
month to month based on the timing of barge deliveries, oil in tanks and
pipeline inventories, and oil pipeline sales nominations.
(2) Net of amounts capitalized.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Quarter Ended Year Ended
---------------------------- ------------------
UNAUDITED (In thousands) 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
-------- -------- -------- -------- --------
REVENUES:
Oil and natural gas sales $ 71,275 $ 77,296 $ 81,890 $290,608 $323,423
Other 791 1,635 1,478 4,684 5,355
-------- -------- -------- -------- --------
Total revenues 72,066 78,931 83,368 295,292 328,778
-------- -------- -------- -------- --------
EXPENSES:
Lease operating expense 20,103 28,684 22,740 84,255 94,100
Property and production
taxes 1,387 1,796 1,593 6,701 6,376
Transportation expense 2,613 2,367 2,325 9,102 9,348
Depletion, depreciation
and amortization 20,313 20,406 22,007 78,504 85,817
Accretion of asset
retirement obligation 1,592 1,623 1,602 6,241 6,423
General and administrative 9,119 9,236 11,297 37,554 39,186
-------- -------- -------- -------- --------
Total expenses 55,127 64,112 61,564 222,357 241,250
-------- -------- -------- -------- --------
Income from operations 16,939 14,819 21,804 72,935 87,528
FINANCING COSTS AND OTHER:
Interest expense 10,045 16,005 16,435 40,584 61,113
Interest rate derivative
realized (gains) losses 4,531 - - 18,094 41,147
Interest rate derivative
unrealized (gains) losses (9,561) - - 13,724 (40,064)
Amortization of deferred
loan costs 507 592 595 2,362 2,310
Loss on extinguishment of
debt - - - - 1,357
Commodity derivative
realized (gains) losses (29,632) (2,571) (19,110) (53,501) (30,656)
Commodity derivative
unrealized (gains) losses
and amortization of
derivative premiums 37,514 (36,001) (6,538) (14,548) (9,993)
-------- -------- -------- -------- --------
Total financing costs and
other 13,404 (21,975) (8,618) 6,715 25,214
-------- -------- -------- -------- --------
Income (loss) before taxes 3,535 36,794 30,422 66,220 62,314
Income tax provision
(benefit) (900) - - (1,300) -
-------- -------- -------- -------- --------
Net income (loss) $ 4,435 $ 36,794 $ 30,422 $ 67,520 $ 62,314
======== ======== ======== ======== ========
Weighted average common
shares outstanding:
Basic 53,451 58,738 58,772 52,249 58,106
Diluted 53,817 58,830 58,821 53,018 58,236
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION
UNAUDITED ($ in thousands) 12/31/10 12/31/11
------------- -------------
ASSETS
Cash and cash equivalents $ 5,024 $ 8,165
Accounts receivable 29,602 30,017
Inventories 6,229 7,411
Prepaid expenses and other current assets 4,585 4,296
Income tax receivable 931 -
Commodity derivatives 26,407 47,768
------------- -------------
Total current assets 72,778 97,657
Net property, plant and equipment 648,044 810,465
Total other assets 30,101 21,622
------------- -------------
TOTAL ASSETS $ 750,923 $ 929,744
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued liabilities $ 45,396 $ 53,098
Interest payable 5,538 21,854
Commodity and interest derivatives 33,483 2,490
------------- -------------
Total current liabilities 84,417 77,442
LONG-TERM DEBT 633,592 686,958
COMMODITY AND INTEREST DERIVATIVES 23,430 308
ASSET RETIREMENT OBLIGATIONS 93,721 92,008
------------- -------------
Total liabilities 835,160 856,716
Total stockholders' equity (84,237) 73,028
------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 750,923 $ 929,744
============= =============
GAAP RECONCILIATIONS
Adjusted Earnings and Adjusted EBITDA
In addition to net income (loss) determined in accordance with
GAAP, we have provided in this release our Adjusted Earnings and
Adjusted EBITDA for recent periods. Both Adjusted Earnings and
Adjusted EBITDA are non-GAAP financial measures that we use as
supplemental measures of our performance.
We define Adjusted Earnings as net income (loss) before the
effects of the items listed in the table below. We calculate the
tax effect of reconciling items by re-performing our period-end tax
calculation excluding the reconciling items from earnings. The
difference between this calculation and the tax expense/benefit
recorded for the period results in the tax effect disclosed below.
We believe that Adjusted Earnings facilitates comparisons to
earnings forecasts prepared by stock analysts and other third
parties. Such forecasts generally exclude the effects of items that
are difficult to predict or to measure in advance and are not
directly related to our ongoing operations. Adjusted Earnings
should not be considered a substitute for net income (loss) as
reported in accordance with GAAP.
We define Adjusted EBITDA as net income (loss) before the
effects of the items listed in the table below. Because the use of
Adjusted EBITDA facilitates comparisons of our historical operating
performance on a more consistent basis, we use this measure for
business planning and analysis purposes, in assessing acquisition
opportunities and in determining how potential external financing
sources are likely to evaluate our business.
We present Adjusted Earnings and Adjusted EBITDA because we
consider them to be important supplemental measures of our
performance. Neither Adjusted Earnings nor Adjusted EBITDA is a
measurement of our financial performance under GAAP and neither
should be considered as an alternative to net income (loss),
operating income or any other performance measure derived in
accordance with GAAP, as an alternative to cash flow from operating
activities or as a measure of our liquidity. You should not assume
that the Adjusted Earnings or Adjusted EBITDA amounts shown are
comparable to similarly named measures disclosed by other
companies.
Quarter Ended Year Ended
---------------------------- ------------------
UNAUDITED ($ in thousands) 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
-------- -------- -------- -------- --------
Adjusted Earnings
Reconciliation
Net Income $ 4,435 $ 36,794 $ 30,422 $ 67,520 $ 62,314
Plus:
Unrealized commodity
(gains) losses 29,678 (37,991) (10,626) (39,356) (20,051)
Unrealized interest rate
derivative (gains) losses (9,561) - - 13,724 (40,064)
Special Committee related
costs - 892 750 - 1,642
Texas severance costs - - - 1,254 -
Loss on extinguishment of
debt - - - - 1,357
Settlement of interest
rate swap contracts - - - - 38,065
Tax effects - - - - -
-------- -------- -------- -------- --------
Adjusted Earnings $ 24,552 $ (305) $ 20,546 $ 43,142 $ 43,263
======== ======== ======== ======== ========
Quarter Ended Year Ended
---------------------------- ------------------
UNAUDITED ($ in thousands) 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
-------- -------- -------- -------- --------
Adjusted EBITDA
Reconciliation
Net income $ 4,435 $ 36,794 $ 30,422 $ 67,520 $ 62,314
Interest expense 10,045 16,005 16,435 40,584 61,113
Interest rate derivative
(gains) losses - realized 4,531 - - 18,094 41,147
Income taxes (900) - - (1,300) -
DD&A 20,313 20,406 22,007 78,504 85,817
Accretion of asset
retirement obligation 1,592 1,623 1,602 6,241 6,423
Amortization of deferred
loan costs 507 592 595 2,362 2,310
Loss on extinguishment of
debt - - - - 1,357
Share-based payments 1,535 1,563 1,781 5,653 6,747
Special Committee related
costs - 892 750 - 1,642
Texas severance costs - - - 1,254 -
Amortization of derivative
premiums 7,836 1,990 4,088 24,808 10,058
Unrealized commodity
derivative (gains) losses 29,678 (37,991) (10,626) (39,356) (20,051)
Unrealized interest rate
derivative (gains) losses (9,561) - - 13,724 (40,064)
-------- -------- -------- -------- --------
Adjusted EBITDA $ 70,011 $ 41,874 $ 67,054 $218,088 $218,813
======== ======== ======== ======== ========
We also provide per BOE G&A expenses excluding costs
associated with the Texas asset sales, costs related to the Special
Committee review of the going-private proposal from the company's
Chairman & CEO, and share-based compensation charges. We
believe that these non-GAAP measures are useful in that the items
excluded do not represent cash expenses directly related to our
ongoing operations. These non-GAAP measures should not be viewed as
an alternative to per BOE G&A expenses as determined in
accordance with GAAP.
UNAUDITED ($ in thousands,
except per BOE amounts) Quarter Ended Year Ended
---------------------------- ------------------
G&A per BOE Reconciliation 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
-------- -------- -------- -------- --------
G&A expense $ 9,119 $ 9,236 $ 11,297 $ 37,554 $ 39,186
Less:
Share-based compensation
expense (1,255) (1,303) (1,591) (4,503) (5,667)
Special Committee related
costs - (892) (750) - (1,642)
Texas severance costs - - - (1,254) -
-------- -------- -------- -------- --------
G&A Expense Excluding
Share-Based Comp,
Severance and Special
Committee Costs 7,864 7,041 8,956 31,797 31,877
MBOE 1,594 1,588 1,639 6,658 6,428
-------- -------- -------- -------- --------
G&A Expense per BOE
Excluding Share-Based
Comp, Severance and
Special Committee Costs $ 4.93 $ 4.43 $ 5.46 $ 4.78 $ 4.96
======== ======== ======== ======== ========
PV-10
The present value of future net cash flows (PV-10 value) is a
non-GAAP measure because it excludes income tax effects. Management
believes that before-tax cash flow amounts are useful for
evaluative purposes since future income taxes, which are affected
by a company's unique tax position and strategies, can make
after-tax amounts less comparable. We derive PV-10 value based on
the present value of estimated future revenues to be generated from
the production of proved reserves, net of estimated production and
future development costs and future plugging and abandonment costs,
using the arithmetic twelve-month average of the first of the month
prices without giving effect to hedging activities or future
escalation, and costs as of the date of estimate without future
escalation, non-property related expenses such as general and
administrative expenses, debt service and depreciation, depletion,
amortization and impairment and income taxes, and discounted using
an annual discount rate of 10%. Management also believes that the
PV-10 based on the NYMEX 5-year forward strip pricing is useful for
evaluative purposes since the use of a strip price provides a
measure based on current market perception.
The following table reconciles the standardized measure of
future net cash flows to PV-10 value (in thousands):
UNAUDITED ($ in thousands) 12/31/2010 12/31/2011
----------- -----------
Standardized measure of discounted future net cash
flows $ 902,901 $ 1,364,146
Add: Present value of future income tax discounted
at 10% 225,795 442,355
----------- -----------
PV-10 at year end SEC prices $ 1,128,696 1,806,501
----------- -----------
Add: Effect of five year NYMEX strip at December
31, 2011 (43,180)
-----------
PV-10 at five year NYMEX strip at December 31, 2011 $ 1,763,321
===========
For further information, please contact Mike Edwards Vice
President (303) 626-8320 http://www.venocoinc.com E-Mail Email
Contact
Grafico Azioni Venoco, Inc. (NYSE:VQ)
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