SOURCE: Venoco, Inc.

Venoco, Inc.

May 01, 2012 07:02 ET

Venoco, Inc. Announces 1st Quarter 2012 Financial and Operational Results

Production of 1.6 Million BOE or 17,425 BOE/d Oil Volumes up More Than 4% Compared to 4Q 2011

DENVER, CO--(Marketwire - May 1, 2012) - 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 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.

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.
Quarter Ended
UNAUDITED (In thousands) 3/31/11 12/31/11 3/31/12
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
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
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
UNAUDITED ($ in thousands) 12/31/11 3/31/12
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
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
Total liabilities 856,716 870,560
Total stockholders' equity 73,028 47,701


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 )
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
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


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

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