Venoco, Inc. (NYSE: VQ) today reported financial and operational
results for the first quarter of 2012. The company reported a net
loss for the quarter of $27.9 million on total revenues of $85.4
million.
Adjusted Earnings, which adjusts for unrealized derivative gains
and losses and certain one-time charges, were $38.5 million for the
quarter up from $20.5 million in the fourth quarter of 2011.
Adjusted EBITDA was $87.8 million in the quarter, up from $67.1
million in the fourth quarter. 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 1.6 million barrels of oil equivalent (MMBOE) for
the quarter, or 17,425 BOE per day (BOE/d).
- Daily oil volumes up 4.5% in first quarter compared to fourth
quarter 2011.
- Ellwood pipeline completed ahead of schedule and in service at
the end of January. Transportation savings and higher price
realization improve field economics.
- Adjusted EBITDA of $87.8 million and Adjusted Earnings of $38.5
million which include $41.2 million from monetization of the
company's 2012 natural gas hedges.
"We continue to be active in our oily, Southern California
legacy assets, with the added benefit of crude oil prices that
surpass WTI," said Ed O'Donnell, Venoco's Chief Operating Officer
and incoming CEO. "We're drilling in our three main oil fields and
expect to grow oil volumes this year which will offset the declines
we expect in natural gas production volumes as we limit capital
expenditures in the Sacramento Basin due to substantially lower
prevailing natural gas prices."
First Quarter Production Production in the
first quarter of 2012 of 17,425 BOE/d was down 2% from the fourth
quarter of 2011 as well as down 2% from the first quarter of 2011.
Daily average oil volumes, however, were up 4.5% in the first
quarter of 2012 compared to the fourth quarter of 2011 and revenue,
over the same period, increased about 2.4%. Daily oil volumes in
the first quarter at the company's West Montalvo field are up
approximately 10% over the fourth quarter of 2011 and up over 30%
from the first quarter of 2011.
"We are pleased to see our daily oil volumes, as we expected,
beginning to increase this year. This will both offset BOE declines
from our natural gas assets, and allow us to realize the fifty to
one price premium on oil versus natural gas," commented Mr.
O'Donnell. "While we are guiding to rather flat production in 2012
compared with 2011, we expect the increase in our oil to natural
gas mix coupled with higher realized oil prices to result in
significant revenue growth. As we stated at year-end, we believe
our production forecasting from the Sevier field will prove to be
conservative. If that is the case, we would see further increases
in our oil volumes and revenues in 2012," Mr. O'Donnell added.
The following table details the company's daily production by
region (BOE(1)/d):
----------------------------------------------------------------------------
Quarter ended
----------------------------------------------------------------------------
Region 3/31/11 12/31/11 3/31/12
----------------------------------------------------------------------------
Sacramento Basin 10,591 10,635 9,970
----------------------------------------------------------------------------
Southern California 7,224 7,175 7,455
----------------------------------------------------------------------------
Total 17,815 17,810 17,425
-------------------------------------=======================================
(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.
----------------------------------------------------------------------------
First Quarter Costs
Venoco's first quarter 2012 lease operating expenses of $15.42
per BOE were up from the fourth quarter and full-year 2011 levels
which were $13.87 and $14.64 per BOE respectively. Costs in the
first quarter were higher due primarily to non-recurring
maintenance at Platforms Gail and Holly and inventory cost of sales
related to emptying the oil tanks at the company's marine
terminal.
The following table details certain of the company's per BOE
metrics for the indicated quarter:
Quarter Ended
--------------------------------------------
UNAUDITED (per BOE) 3/31/11 12/31/11 3/31/12
-------------- -------------- --------------
Lease Operating Expenses $ 13.52 $ 13.87 $ 15.42
Production/Property Taxes 0.97 0.97 1.02
DD&A Expense 13.53 13.43 14.03
G&A Expense (1) 5.22 5.46 5.37
(1) Net of amounts capitalized and excluding stock-based
compensation costs and costs related to the going-private
transaction. See the end of this release for a reconciliation of
G&A per BOE.
Capital Investment First Quarter 2012
Venoco's first quarter capital expenditures for exploration,
development and other spending were $62 million, including $46
million for drilling and rework activities, $6 million for
facilities, and $10 million for land, seismic and capitalized
G&A.
In the Sacramento Basin, the company spent $10 million or 17% of
its first quarter capital expenditures, spudding three wells and
performing 95 recompletions. The company's 2012 budget provides for
total capital expenditures of $32 million in the basin. The budget
contemplates drilling two additional wells and performing a total
of 180 recompletions and seven hydraulic fractures, however, in
light of low natural gas prices, the company has curtailed drilling
in the Sacramento Basin.
The company's Southern California legacy fields accounted for
$29 million or 47% of its first quarter capital expenditures. Three
wells were spud at the West Montalvo field, all to offshore
bottom-hole locations. The company completed one of those wells in
the quarter along with two other wells that were spud in 2011.
Another of those wells was completed early in the second quarter.
At the Sockeye field, the company spud one well in the quarter.
That dual-completion well targets production from the Monterey
shale formation and also injects into the Upper Topanga waterflood.
At the South Ellwood field, the company spud one well late in the
quarter, which was recently completed and expects to spud a second
well this week. Both wells at South Ellwood target the Monterey
shale.
The company's 2012 capital expenditure budget for legacy
Southern California properties is $123 million and includes plans
to drill seven wells at West Montalvo. 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 had onshore Monterey capital expenditures of $22
million or 35% of its total first quarter capital expenditures. As
part of this activity, the company spud two wells in the first
quarter of 2012 in the Sevier field, one of which was completed in
the quarter. The company also recompleted a well it drilled in 2011
in its acreage in the greater San Joaquin Valley.
The company's 2012 capital expenditure budget for the onshore
Monterey shale development is $100 million, focused on delineation
and production at the Sevier field where the company plans to spud
15 to 20 wells. 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.
"We are anxious to see sustained results, but we have had
several good well tests on recent completions. One zone flowed at a
peak, 24-hour gross rate of 143 barrels of oil per day. In another
well, we had a peak, 24-hour gross flowback rate of 196 barrels of
oil per day from one zone and 98 barrels of oil per day from a
second zone. Coupled with the recent test results, the fundamental
well data -- geology, logs, cores and production testing -- is
still very encouraging," commented Mr. O'Donnell. "We are currently
forecasting minimal production volumes from Sevier on an annualized
basis, but we believe there is a good chance we'll see sustained
production before the end of the year."
The company entered into a new crude oil sales contract on
February 1, 2012 for its South Ellwood field concurrent with
commencement of shipping production via the new pipeline. The
contract is tied to Napo prices -- an Ecuadorian, waterborne crude
-- that has been tracking above WTI. Venoco's current price
realization for South Ellwood crude with the new contract compared
to the previous contract is about $10 to $15 per barrel higher.
The balance of the company's crude oil, as of April 1st is sold
under a contract tied to California postings at the Buena Vista
field. The effect of the new contract on price realizations for
crude from those fields in April has been positive by about $20 per
barrel. The company's oil hedging contracts include basis swaps
between WTI and Brent that have reduced the net by approximately
$10 per barrel.
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 January 16,
2012, the company announced that it had entered into a definitive
merger agreement under which Tim Marquez, Venoco's Chairman and
CEO, will, through a wholly owned affiliate, acquire all of the
outstanding shares of Venoco he does not already own for $12.50 per
share in cash. Mr. Marquez is currently the beneficial owner of
approximately 50.3% of Venoco's common stock.
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, Tuesday, May 1, 2012 at
12:00 p.m. Eastern time (10 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) 237-9752 and use conference code
50520898. International participants can call (617) 847-8706 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 40970132. 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, 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 12/31/11 3/31/12 Change 3/31/11 3/31/12 Change
-------- -------- ------ -------- -------- ------
Production Volume:
Oil (MBbls) (1) 620 641 3% 608 641 5%
Natural Gas (MMcf) 6,111 5,668 -7% 5,972 5,668 -5%
-------- -------- ------ -------- -------- ------
MBOE 1,639 1,586 -3% 1,603 1,586 -1%
======== ======== ====== ======== ======== ======
Daily Average
Production Volume:
Oil (Bbls/d) 6,739 7,044 5% 6,756 7,044 4%
Natural Gas (Mcf/d) 66,424 62,286 -6% 66,356 62,286 -6%
-------- -------- ------ -------- -------- ------
BOE/d 17,810 17,425 -2% 17,815 17,425 -2%
======== ======== ====== ======== ======== ======
Oil Price per Barrel
Produced (in
dollars):
Realized price
before hedging $ 93.79 $ 98.66 5% $ 86.38 $ 98.66 14%
Realized hedging
gain (loss) (1.35) (5.75) 326% (1.51) (5.75) 281%
-------- -------- ------ -------- -------- ------
Net realized price $ 92.44 $ 92.91 1% $ 84.87 $ 92.91 9%
======== ======== ====== ======== ======== ======
Natural Gas Price
per Mcf (in
dollars):
Realized price
before hedging $ 3.60 $ 2.76 -23% $ 4.03 $ 2.76 -32%
Realized hedging
gain (loss) 1.29 0.63 -51% 1.07 0.63 -41%
-------- -------- ------ -------- -------- ------
Net realized price $ 4.89 $ 3.39 -31% $ 5.10 $ 3.39 -34%
======== ======== ====== ======== ======== ======
Expense per BOE (in
dollars):
Lease operating
expenses $ 13.87 $ 15.42 11% $ 13.52 $ 15.42 14%
Production and
property taxes $ 0.97 $ 1.02 5% $ 0.97 $ 1.02 5%
Transportation
expenses $ 1.42 $ 2.78 96% $ 1.24 $ 2.78 124%
Depreciation,
depletion and
amortization $ 13.43 $ 14.03 4% $ 13.53 $ 14.03 4%
General and
administrative (2) $ 6.89 $ 7.79 13% $ 6.13 $ 7.79 27%
Interest expense $ 10.03 $ 9.91 -1% $ 7.92 $ 9.91 25%
(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 pipeline inventories, oil
pipeline sales nominations, and prior to February 2012, the timing of
barge deliveries and oil in tanks.
(2) Net of amounts capitalized.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Quarter Ended
----------------------------
UNAUDITED (In thousands) 3/31/11 12/31/11 3/31/12
-------- -------- --------
REVENUES:
Oil and natural gas sales $ 78,319 $ 81,890 $ 83,388
Other 871 1,478 1,975
-------- -------- --------
Total revenues 79,190 83,368 85,363
-------- -------- --------
EXPENSES:
Lease operating expense 21,676 22,740 24,450
Property and production taxes 1,548 1,593 1,615
Transportation expense 1,986 2,325 4,412
Depletion, depreciation and amortization 21,691 22,007 22,254
Accretion of asset retirement obligation 1,590 1,602 1,391
General and administrative 9,829 11,297 12,361
-------- -------- --------
Total expenses 58,320 61,564 66,483
-------- -------- --------
Income from operations 20,870 21,804 18,880
FINANCING COSTS AND OTHER:
Interest expense 12,697 16,435 15,711
Interest rate derivative realized (gains)
losses 41,147 - -
Interest rate derivative unrealized (gains)
losses (40,064) - -
Amortization of deferred loan costs 531 595 569
Loss on extinguishment of debt 1,357 - -
Commodity derivative realized (gains) losses (5,468) (19,110) (41,096)
Commodity derivative unrealized (gains) losses
and amortization of derivative premiums 34,595 (6,538) 71,634
-------- -------- --------
Total financing costs and other 44,795 (8,618) 46,818
-------- -------- --------
Income (loss) before taxes (23,925) 30,422 (27,938)
Income tax provision (benefit) - - -
-------- -------- --------
Net income (loss) $(23,925) $ 30,422 $(27,938)
======== ======== ========
Weighted average common shares outstanding:
Basic 56,159 58,772 58,910
Diluted 56,159 58,821 58,910
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION
UNAUDITED ($ in thousands) 12/31/11 3/31/12
--------- ---------
ASSETS
Cash and cash equivalents $ 8,165 $ 23
Accounts receivable 30,017 29,810
Inventories 7,411 6,900
Other current assets 4,296 3,966
Commodity derivatives 47,768 5,398
--------- ---------
Total current assets 97,657 46,097
Net property, plant and equipment 810,465 850,771
Total other assets 21,622 21,393
--------- ---------
TOTAL ASSETS $ 929,744 $ 918,261
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued liabilities $ 53,098 $ 46,254
Interest payable 21,854 6,182
Commodity and interest derivatives 2,490 23,714
--------- ---------
Total current liabilities 77,442 76,150
LONG-TERM DEBT 686,958 694,141
COMMODITY AND INTEREST DERIVATIVES 308 6,682
ASSET RETIREMENT OBLIGATIONS 92,008 93,587
--------- ---------
Total liabilities 856,716 870,560
Total stockholders' equity 73,028 47,701
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 929,744 $ 918,261
========= =========
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
-------------------------------
UNAUDITED ($ in thousands) 3/31/11 12/31/11 3/31/12
--------- --------- ---------
Adjusted Earnings Reconciliation
Net Income $ (23,925) $ 30,422 $ (27,938)
Plus:
Unrealized commodity (gains) losses 32,605 (10,626) 63,839
Unrealized interest rate derivative (gains)
losses (40,064) - -
Going private related costs - 750 2,628
Loss on extinguishment of debt 1,357 - -
Settlement of interest rate swap contracts 38,065 - -
Tax effects - - -
--------- --------- ---------
Adjusted Earnings $ 8,038 $ 20,546 $ 38,529
========= ========= =========
Quarter Ended
-------------------------------
UNAUDITED ($ in thousands) 3/31/11 12/31/11 3/31/12
--------- --------- ---------
Adjusted EBITDA Reconciliation
Net income $ (23,925) $ 30,422 $ (27,938)
Interest expense 12,697 16,435 15,711
Interest rate derivative (gains) losses -
realized 41,147 - -
Income taxes - - -
DD&A 21,691 22,007 22,254
Accretion of asset retirement obligation 1,590 1,602 1,391
Amortization of deferred loan costs 531 595 569
Loss on extinguishment of debt 1,357 - -
Share-based payments 1,824 1,781 1,540
Going private related costs - 750 2,628
Amortization of derivative premiums 1,990 4,088 7,795
Unrealized commodity derivative (gains)
losses 32,605 (10,626) 63,839
Unrealized interest rate derivative (gains)
losses (40,064) - -
--------- --------- ---------
Adjusted EBITDA $ 51,443 $ 67,054 $ 87,789
========= ========= =========
We also provide per BOE G&A expenses excluding costs
associated with the going-private transaction, 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
-------------------------------
G&A per BOE Reconciliation 3/31/11 12/31/11 3/31/12
--------- --------- ---------
G&A expense $ 9,829 $ 11,297 $ 12,361
Less:
Share-based compensation expense (1,454) (1,591) (1,220)
Going private related costs - (750) (2,628)
--------- --------- ---------
G&A Expense Excluding Share-Based Comp
Going Private Costs 8,375 8,956 8,513
MBOE 1,603 1,639 1,586
--------- --------- ---------
G&A Expense per BOE Excluding Share-Based
Comp and Going Private Costs $ 5.22 $ 5.46 $ 5.37
========= ========= =========
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) 12/31/2011
-----------
Standardized measure of discounted future net cash flows $ 1,364,146
Add: Present value of future income tax discounted at 10% 442,355
-----------
PV-10 at year end SEC prices 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
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