The following discussion and analysis should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in our Annual Report on Form 10-K for the year ended December 31, 2007 as well as with the financial statements and related notes and the other information appearing elsewhere in this report. As used in this report, unless the context otherwise indicates, references to "we," "our," "ours," and "us" refer to Venoco, Inc. and its subsidiaries collectively.

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to be relatively low risk and through selective acquisitions of underdeveloped properties. Our average net production was 21,949 BOE/d in the third quarter of 2008, compared to 21,033 BOE/d in the second quarter of 2008 and 20,701 BOE/d in the third quarter of 2007.

In the execution of our strategy, our management is principally focused on increasing our reserves of oil and natural gas and on increasing annual production through development, exploitation and exploration activities and acquisitions. Our management is also focused on the risks and opportunities associated with current oil and natural gas prices, which remain high compared to longer-term historical averages, and on the goal of maximizing production rates while operating in a safe manner.

Capital Expenditures

We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other projects. Our development, exploitation and exploration capital expenditure budget for 2008 is $300.0 million, of which approximately $210.4 million (excluding changes in accrued capital expenditures) was expended in the first nine months of 2008. We expect to spend approximately 55% of the budgeted amount on projects in the Sacramento Basin, 22% in Southern California and 15% in Texas, with the remaining 8% going towards exploration projects in a variety of areas. Our 2009 development, exploitation and exploration capital expenditure budget is $300 million, of which approximately 50% is expected to be deployed in the Sacramento Basin, 19% in Southern California and 4% in Texas, with the remainder going towards exploration 17% and leasehold and capitalized general and administrative expenses 10%. We have a significant inventory of projects and should market conditions become more favorable we could potentially look to increase our capital spending later in 2009.

The aggregate levels of capital expenditures for the remainder of 2008 and 2009, and the allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from our estimates. The following summarizes certain significant aspects of our 2008 capital spending program and the outlook for 2009:

Southern California-Exploitation and Development

Our primary focus in Southern California in 2008 is on development activities in the West Montalvo field, where we are continuing an aggressive workover, recompletion and return to production program that we began when we acquired the field in May 2007. We worked over six wells

and returned seven wells to production during the first nine months of the year and plan to return an additional two wells to production during the fourth quarter. We also plan to drill three new development wells in the field during the year. We spud the first of these wells in late September, the second in October, and anticipate spudding the third well in November. We plan to drill three additional infill wells on the onshore portion of the field in 2009.

In the Sockeye field, we continue to implement our waterflood program from platform Gail and are working on the evaluation and design of a possible expansion of the program. During the first nine months of the year, we redrilled one well as an injector and performed four successful workovers in the field. We also continue to develop our plans for additional infill development drilling, waterflood expansion and natural gas production. We are also planning to fracture a Monterey well at Sockeye in 2009.

In the South Ellwood field, the permitting process continues for our full-field development project. We received the draft environmental impact report for this project from the California State Lands Commission in June. We have provided comments on the report and are now focused on the project approval hearings which we expect to commence during either the fourth quarter of 2008 or first quarter of 2009. Key components of the project include an extension of our current lease area (which would effectively double the size of the existing lease area) and the installation of an onshore oil transport pipeline to replace the existing barge. Development of the extended lease area can be accomplished from the field's existing platform. We have been working on the pipeline permitting process and right-of-way for the pipeline in 2008 and our 2009 budget includes expenditures for certain long-lead items for the full-field development project in anticipation of regulatory approvals.

Sacramento Basin-Exploitation and Development

In the Sacramento Basin, we continue to pursue our infill drilling program in the greater Grimes and Willows fields. We currently have five drilling rigs and five workover/completion rigs working in the basin and expect to drill approximately 120 new wells and perform more than 125 workovers and recompletions there during 2008. In the first nine months of 2008, we spudded 84 wells, completed 61 wells, and performed 98 workovers and recompletions in the basin.

We also continue to pursue our hydraulic fracturing program in the basin, a program that could potentially enhance production and reserves significantly. We initiated the program in November 2007 and have fractured 47 wells during the first nine months of 2008. We are encouraged by the early success of the program and continue to analyze results in order to optimize future fracture stimulations in the basin. We plan to fracture approximately 75 wells in the basin during 2008. Our 2009 budget will generate similar drilling, workover and fracturing activity next year.

Texas-Exploitation and Development

In Texas, our focus in 2008 is on the continuation of our workover and recompletion programs in the Hastings complex and the Manvel field. During the first nine months of the year, we performed 83 workovers and recompletions and converted 14 wells into injectors at the Hastings complex. We are also focused on lowering operating expenses in the Hastings complex as we reduce our remediation and redevelopment activities there. At Manvel, we performed seven workovers and converted one well to an injector during the first nine months of the year. During the fourth quarter, we plan to continue our redevelopment work at Hastings and Manvel and to drill up to three new development wells in our Texas fields, including two at Manvel. Our 2009 budget includes capital for four new development wells, including two at Manvel.

Exploration Activities

During the first nine months of the year we've drilled, or started drilling, two higher impact exploration wells in Texas and six in the Sacramento Basin. We plan to drill a total of ten higher impact exploration wells during 2008.

Acquisitions and Divestitures

West Montalvo and Manvel Acquisitions. We acquired the West Montalvo field in Ventura County, California in May 2007 for $61.3 million. We acquired the Manvel field in Brazoria County, Texas, and certain other fields in Texas, in April 2007 for $44.5 million.

Hastings Complex Sale. In November 2006, we entered into an agreement with a subsidiary of Denbury Resources Inc. pursuant to which Denbury has an option to acquire the majority of our properties in the Hastings complex for use in a proposed CO2 enhanced recovery project in which we will have a continuing interest. On August 29, 2008, we entered into an amendment to the agreement pursuant to which Denbury exercised its option to acquire the properties effective January 1, 2009. Denbury will either purchase the properties or, if we so elect, enter into a volumetric production payment or similar arrangement with us with respect to the properties. Unless we and Denbury agree otherwise, the purchase price or volumetric production payment will be based on the value of the properties as of December 31, 2008 determined with reference to the net proved reserves associated with the properties based on then-existing operations and NYMEX forward strip pricing, subject to certain adjustments.

Other. We have an active acreage acquisition program and we regularly engage in acquisitions (and, to a lesser extent, dispositions) of oil and natural gas properties, primarily in and around our existing core areas of operations.

Certain Trends Affecting our Results of Operations

Expected Production. We expect that the continued execution of our capital expenditure program will result in increases in our average net production from each of our operating areas over the remainder of 2008. In Southern California, we expect to achieve production increases from the drilling and workover/recompletion programs we began in the West Montalvo field in 2007 and the workover program we began this year on Platform Gail in the Sockeye field. In the Sacramento Basin, we are continuing our multi-year drilling program and our hydraulic fracturing program and anticipate production increases from both. We continue to assess and develop plans for a further expansion of our activities in the area. We also expect production to increase in the Hastings complex as a result of the enhancement of our water processing and injection capabilities and the continuation of our workover and recompletion program. At the Manvel field, we are implementing a similar redevelopment program to increase production by upgrading our fluid handling and injection capacity and performing workovers and recompletions. In 2009, the sale of our producing properties in the Hastings complex in the first quarter will impact our overall production levels. Excluding 2008 production from those properties, however, we expect to grow production in 2009 relative to 2008, primarily as a result of the continued development of the projects described above. Our expectations with respect to future production rates are subject to a number of uncertainties, including those associated with third party services, oil and natural gas prices, events resulting in unexpected downtime, permitting issues, drilling success rates, pipeline capacity, and other factors, including those referenced in "Risk Factors."

Commodity Prices. Oil and natural gas prices for the first nine months of 2008 have generally been higher than the comparable period in 2007, which has contributed to significant increases in our oil and natural gas sales in the first nine months of 2008. Rising commodity prices have also caused us

to incur unrealized commodity derivative losses in the first nine months of 2008. However, commodity prices have declined substantially since June 30, 2008, which has caused us to recognize significant unrealized commodity derivative gains in the third quarter of 2008. These unrealized gains and losses resulted from mark-to-market valuations of derivative positions that are not accounted for as cash flow hedges and are reflected as unrealized commodity derivative gains and losses in our income statement. Payments actually due to or from counterparties in the future on these derivatives will typically be offset by corresponding changes in prices ultimately received from the sale of our production. As a result of volatility in oil and natural gas prices, we will likely continue to experience significant unrealized commodity derivative gains and losses. Changes in oil and natural gas prices will also continue to affect our oil and natural gas sales, and those prices will also be a significant factor in determining the proceeds we receive in the sale of the Hastings properties. Oil and natural gas prices are affected by many factors outside of our control, including changes in worldwide supply and demand, and we cannot predict future changes in those prices.

Results of Operations

    The following table reflects the components of our oil and natural gas
production and sales prices and sets forth our operating revenues, costs and
expenses on a BOE basis for the three and nine months ended September 30, 2007
and 2008.

                                         Three Months Ended           Nine Months Ended
                                            September 30,               September 30,
                                         2007           2008         2007           2008
Production Volume:
Oil (MBbls)(1)                             1,071          1,036        2,960          2,995
Natural gas (MMcf)                         5,001          5,900       13,926         17,110
MBOE                                       1,905          2,019        5,281          5,846
Daily Average Production Volume:
Oil (Bbls/d)                              11,641         11,261       10,842         10,931
Natural gas (Mcf/d)                       54,359         64,130       51,011         62,445
BOE/d                                     20,701         21,949       19,344         21,339
Oil Price per Bbl Produced
(in dollars):
Realized price                          $  66.73       $ 109.08     $  58.00       $ 104.81
Realized commodity derivative gain
(loss) and amortization of
commodity derivative premiums              (2.91 )       (32.08 )      (0.99 )       (29.69 )

Net realized price                      $  63.82       $  77.00     $  57.01       $  75.12

Natural Gas Price per Mcf
(in dollars):
Realized price                          $   5.71       $   8.92     $   6.56       $   9.07
Realized commodity derivative loss
and amortization of commodity
derivative premiums                         0.73          (0.15 )       0.25          (0.08 )

Net realized price                      $   6.44       $   8.77     $   6.81       $   8.99

MBOE Sales Volume(2)                       1,889          1,932        5,296          5,802
Average Sales Price per BOE(3)          $  50.90       $  63.53     $  48.44       $  63.34

                                             Three Months Ended         Nine Months Ended
                                                September 30,             September 30,
                                             2007          2008        2007          2008
Expense per BOE:
Production expenses(4)                       $ 14.90       $ 21.01     $ 15.04       $ 18.40
Transportation expenses                         0.60          0.82        0.84          0.74
Depreciation, depletion and amortization       13.32         16.31       13.17         16.09
General and administrative expense(5)           4.00          5.07        4.67          5.38
Interest expense                                8.13          6.59        8.44          7.02


--------------------------------------------------------------------------------
   º (1)

º (2)
º Amounts shown are BOE sales volumes for both offshore and onshore properties.

º (3)
º Amounts shown are based on oil and natural gas sales, net of inventory changes, realized commodity derivative gains (losses), and amortization of commodity derivative premiums, divided by sales volumes.

º (4)
º Production expenses are comprised of lease operating expenses and production/property taxes.

º (5)
º Net of amounts capitalized.

Comparison of Quarter Ended September 30, 2008 to Quarter Ended September 30, 2007

Oil and Natural Gas Sales. Oil and natural gas sales increased $62.3 million (65%) to $158.0 million for the quarter ended September 30, 2008 from $95.7 million for the same period in 2007. The increase was primarily due to a 25% increase in average sales prices and a 6% increase in production as described below.

Oil sales increased by $37.8 million (56%) in the third quarter of 2008 to $105.4 million compared to $67.6 million in the third quarter of 2007. Oil production decreased by 3%, with production of 1,036 MBbl in the third quarter of 2008 compared to 1,071 MBbl in the third quarter of 2007. The production decrease was primarily related to curtailed production at the South Ellwood field due to an interruption in barge service. The barge that transports the oil produced from the field was out of service for scheduled repairs for the majority of August and all of September. In addition, the Hastings complex and the Manvel field were shut in for seven to ten days due to Hurricane Ike in September. Our average realized price for oil increased $42.35 (63%) to $109.08 per Bbl for the period.

Natural gas sales increased $24.5 million (87%) in the third quarter of 2008 to $52.6 million compared to $28.1 million in the third quarter of 2007. Natural gas production increased 18%, with production of 5,900 MMcf in the third quarter of 2008 compared to 5,001 MMcf in the third quarter of 2007. The increase was due primarily to drilling, recompletion and hydraulic fracturing activities in the Sacramento Basin. Our average realized price for natural gas increased $3.21 (56%) to $8.92 per Mcf for the period.

Other Revenues. Other revenue remained relatively constant at $1.1 million in the third quarter of 2008 compared to $1.0 million in the third quarter of 2007.

Production Expenses. Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, increased $14.0 million (49%) to $42.4 million in the third quarter of

2008 from $28.4 million in the third quarter of 2007. The increase was primarily due to non-recurring maintenance costs related to certain wells in the Sockeye field, a significant increase in electricity usage and rates in Texas, and an increase in the number of producing wells at other properties. Also contributing to the overall increase in production expenses was an increase in secured and supplemental property taxes related to our California properties. On a per unit basis, LOE increased to $17.89 per BOE in the third quarter of 2008 from $13.73 per BOE in the same period in 2007.

Transportation Expenses. Transportation expenses increased $0.6 million (45%) to $1.7 million in the third quarter of 2008 from $1.1 million in the third quarter of 2007. On a per BOE basis, transportation expenses increased $0.22 per BOE, from $0.60 per BOE in the third quarter of 2007 to $0.82 per BOE in the third quarter of 2008. The increase is primarily related to maintenance costs incurred in the third quarter of 2008 on the barge that delivers the South Ellwood oil production.

Depletion, Depreciation and Amortization (DD&A). DD&A expense increased $7.5 million (30%) to $32.9 million in the third quarter of 2008 from $25.4 million in the third quarter of 2007. DD&A expense rose $2.99 per BOE, from $13.32 per BOE in the third quarter of 2007 to $16.31 per BOE in the third quarter of 2008. The increase was primarily due to a higher depletion expense based on an increase in our oil and natural gas property cost resulting from our capital expenditure program.

Accretion of Abandonment Liability. Accretion expense was $1.0 million in the third quarter of 2008 compared to $0.9 million in the third quarter of 2007. The increase was due to accretion from new wells drilled and completed in 2007 and the first nine months of 2008.

General and Administrative (G&A). G&A expense increased $2.6 million (34%) to $10.2 million in the third quarter of 2008 from $7.6 million in the third quarter of 2007. The increase primarily resulted from an increase in our professional staff and related infrastructure. Non-cash SFAS 123R compensation expense charged to G&A decreased $0.1 million (6%) from $1.2 million in 2007 to $1.1 million in 2008 as a result of the settlement of an employment contract in the third quarter of 2007. Excluding the effect of the non-cash SFAS 123R compensation expense charges, G&A expense increased $1.13 from $3.37 per BOE in the third quarter of 2007 to $4.50 per BOE in the third quarter of 2008.

Interest Expense, Net. Interest expense, net of interest income, decreased $2.2 million (14%) from $15.5 million in the third quarter of 2007 to $13.3 million in the third quarter of 2008. The decrease was primarily the result of lower interest rates realized during the third quarter of 2008, partially offset by an increase in average debt outstanding.

Amortization of Deferred Loan Costs. Amortization of deferred loan costs decreased $0.3 million, from $1.0 million in the third quarter of 2007 to $0.7 million in the third quarter of 2008. The decrease was primarily due to the amendment to the revolving credit facility in May 2008 which extended the maturity date of the facility.

Interest Rate Derivative Losses (Gains), Net. Changes in the fair value of our interest rate swap derivative instruments resulted in unrealized gains of $0.6 million in the third quarter of 2008 and a loss of $8.3 million in the 2007 period. The change between periods is the result of an increase in estimated interest rates used to determine the fair value of the derivative instruments at September 30, 2008 and a decrease in estimated interest rates in the third quarter of 2007. Realized interest rate swap losses were $3.4 million in the third quarter of 2008 compared to nil in the third quarter of 2007.

Commodity Derivative Losses, Net. The following table sets forth the components of commodity derivative losses, net in our consolidated statements of operations for the periods indicated (in thousands):

                                                    Three Months Ended
                                                      September 30,
                                                   2007            2008
         Realized commodity derivative          $       (530 )   $   34,095
         (gains) losses
         Unrealized commodity derivative               8,576       (338,773 )
         (gains) losses
         Amortization of derivative premiums           1,650          1,626

         Total                                  $      9,696     $ (303,052 )

Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative losses in the third quarter of 2008 reflect the settlement of contracts at prices above the relevant strike prices, while the realized derivative gain in the third quarter of 2007 reflects the settlement of contracts at prices below the relevant strike prices. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. The change in unrealized commodity derivative (gains) losses reflects an increase in the notional volumes under derivative contracts outstanding in the 2008 period and a decrease in the futures prices used to estimate the fair value of those contracts at the end of the period. Derivative premiums are amortized over the term of the underlying derivative contracts.

Income Tax Expense (Benefit). The net income in the third quarter of 2008 resulted in income tax expense of $136.2 million compared to the income tax benefit of $1.7 million for the third quarter of 2007.

Net Income (Loss). Net income for the third quarter of 2008 was $220.9 million compared to net income of $0.5 million for the same period in 2007. The change between periods is the result of the items discussed above.

Comparison of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2007

Oil and Natural Gas Sales. Oil and natural gas sales increased $202.8 million (78%) to $461.8 million for the nine months ended September 30, 2008 from $259.0 million for the same period in 2007. The increase was primarily due to a 31% increase in average sales prices and an 11% increase in production, as further described below.

Oil sales increased by $138.3 million (82%) in the first nine months of 2008 to $306.7 million from $168.4 million in the first nine months of 2007. Oil production rose 1%, with production of 2,995 MBbl in the first nine months of 2008 compared to 2,960 MBbl in the first nine months of 2007. The production increase was attributable primarily to the effect of a full period of production from the Manvel field, which was purchased in April 2007, and from the West Montalvo field, which was purchased in May 2007. The increase was substantially offset by reduced production from the South Ellwood field as a result of an interruption in barge service for scheduled repairs during the majority of August and all of September 2008. In addition, the Hastings and Manvel fields were shut in for seven to ten days as a result of Hurricane Ike in the third quarter of 2008. Our average realized price for oil increased $46.81 (81%) to $104.81 per Bbl for the period.

Natural gas sales increased $64.4 million (71%) in the first nine months of 2008 to $155.1 million compared to $90.7 million in the first nine months of 2007. Natural gas production increased 23%, with production of 17,110 MMcf compared to 13,926 MMcf in the first nine months of 2007. The increase

was due primarily to drilling, recompletion and hydraulic fracturing activities in the Sacramento Basin. Our average realized price for natural gas increased $2.51 (38%) to $9.07 per Mcf for the period.

Other Revenues. Other revenue remained relatively flat at $2.8 million in the first nine months of 2008 compared to $2.6 million in the first nine months of 2007.

Production Expenses. Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, increased $28.2 million (35%) to $107.6 million in the first nine months of 2008 from $79.4 million in the first nine months of 2007. The increase was due to (i) a significant increase in electricity usage and rates in Texas in the third quarter of 2008,
(ii) non-recurring maintenance costs incurred at Sockeye in 2008, (iii) the . . .