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Article by DailyStocks_admin    (12-15-08 08:05 AM)

Venoco Inc. CEO Timothy Marquez bought 750000 shares on 12-08-2008 at $2.8

BUSINESS OVERVIEW

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Since our founding in 1992, our core areas of focus have been offshore and onshore California. Our principal properties are located offshore southern California, onshore in California's Sacramento Basin and onshore along the Gulf Coast of Texas, and are characterized by long reserve lives, predictable production profiles and substantial opportunities for further exploitation and development.

We are one of the largest independent oil and natural gas companies in California based on production volumes. According to a reserve report prepared by DeGolyer & MacNaughton, we had proved reserves of approximately 99.9 MMBOE as of December 31, 2007, of which 64% were oil and 61% were proved developed. The PV-10 value of our proved reserves as of that date was approximately $2.4 billion. Our definition of PV-10, and a reconciliation of a standardized measure of discounted future net cash flows to PV-10, is set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operation—PV-10 Value and Reserve Replacement Costs." Our average net production in the fourth quarter of 2007 was 20,098 BOE/d, implying a proved reserves to production ratio of 13.6 years.

Our Strengths

We believe that the following strengths provide us with significant competitive advantages:

High quality asset base with a long reserve life. Most of our reserves are located in fields that have large volumes of hydrocarbons in place in multiple geologic horizons. One of our primary objectives is to use our engineering expertise to improve recovery rates from these fields and thereby increase our production and reserves. Our offshore California fields and our Texas Gulf Coast fields generally have well-established production histories and exhibit relatively moderate production declines. As of December 31, 2007, our proved reserves to production ratio was 13.6 years and our proved developed reserves to production ratio was 8.3 years, in each case based on production during the fourth quarter of 2007. We believe that this relatively stable base of long-lived production is a strong platform to support further growth in our reserves and production.

Significant drilling inventory and growth potential. We believe that the continued exploitation and development of our properties will allow us to increase our proved reserves and our average net daily production even if we do not make additional acquisitions. Growth projects that we expect to pursue include a full-field development project, including an extension of the lease area, in our South Ellwood field and a hydraulic fracturing program in the Sacramento Basin. We have also entered into an agreement with Denbury Resources Inc. relating to a potential CO 2 enhanced recovery project at the Hastings complex in Texas. See "—Description of Properties" for more information regarding each of these projects. As of December 31, 2007, we had identified 620 drilling locations on our properties, and we anticipate identifying additional locations on those properties as we pursue our exploitation and development activities.

Attractive reserve replacement costs. From our inception in 1992 through December 31, 2007, we made approximately $1.5 billion in capital expenditures to acquire, develop and/or discover 161.5 MMBOE of proved reserves at an average reserve replacement cost (including reserve revisions) of $9.30 per BOE. These capital expenditures consisted of $732.2 million used to complete 45 acquisitions and $769.5 million used for exploitation, development and exploration projects. See "Management's Discussion and Analysis of Financial Condition and Results of Operation—PV-10 Value and Reserve Replacement Costs" for a description of how we calculate reserve replacement cost.

Strong position in the Sacramento Basin. We have considerable expertise in the exploration, exploitation and development of properties in the Sacramento Basin, where we have operated since 1996 and are currently one of the largest producers. We believe that our experience, expertise and substantial presence in the basin will allow us to take advantage of attractive acquisition, exploration, exploitation and development opportunities there. In addition, we believe that the basin's proximity to northern California natural gas markets, its substantial gathering infrastructure and pipeline capacity and the relatively small differential to NYMEX prices received for natural gas produced there contribute to the value of our position.

Extensive knowledge of the Monterey shale formation. A substantial portion of our production consists of offshore production from an unconventional reservoir, the fractured Monterey shale formation in California. Our technical team has extensive offshore experience with the evaluation and exploitation of this reservoir. We believe that there are significant exploration, exploitation and development opportunities relating to the Monterey formation onshore as well, and that our offshore expertise will help us take advantage of those opportunities.

Experienced, proven management and operations team. The members of our management team have an average of over 25 years of experience in the oil and natural gas industry. Prior to founding our company in 1992, our CEO, Timothy Marquez, worked for Unocal for 13 years in both engineering and managerial positions. Our operations team has significant experience in the California and Texas oil and natural gas industry across a broad range of disciplines, including geology, drilling and operations, and regulatory and environmental matters. Our team includes 48 engineers and geoscientists as of December 31, 2007. We believe that our experience and knowledge of the California oil and natural gas industry, including the unconventional Monterey reservoir, are important competitive advantages for us.

High percentage of operated properties. We have operating control of substantially all of our properties, operating approximately 95% of our production in the fourth quarter of 2007. Maintaining control of our properties allows us to use our technical and operational expertise to manage overhead, production and drilling costs and capital expenditures and to control the timing of exploration, exploitation and development activities.

Reputation for environmental, safety and regulatory compliance. We believe that we have established a reputation among regulators and other oil and natural gas companies as having a commitment to safe environmental practices. For example, the state of California has presented us with awards for outstanding lease maintenance at our Beverly Hills and Santa Clara Avenue fields. We believe that our reputation is an important advantage for us when we are competing to acquire properties, particularly those in environmentally sensitive areas, because sellers are often concerned that they could be held responsible for environmental problems caused by the purchaser.

Good relationships with local communities. We have devoted substantial effort towards establishing and maintaining good relationships with the communities in which we operate, and have won several awards for our community service and outreach programs. We believe that maintaining strong community ties can, among other things, help to facilitate the process of obtaining the governmental approvals needed to expand our operations.

Our Strategy

We intend to continue to use our competitive strengths to advance our corporate strategy. The following are key elements of that strategy:

Grow through relatively low-risk exploration, exploitation and development projects. We operate properties with substantial volumes of remaining hydrocarbons. We believe that we can expand reserves and increase production from these properties on a cost-effective basis with relatively limited risk. We expect that our exploration, exploitation and development capital expenditures in 2008 will be approximately $235.0 million.

Make opportunistic acquisitions of underdeveloped properties. We pursue acquisitions that we believe will expand our reserves and production on a cost-effective basis. Our primary focus is on operated interests in large, mature fields that are located in our core operating regions and have significant production histories, established proved reserves and potential for further exploitation and development. Historically, we have had success acquiring offshore California properties from major oil companies, including Chevron and ExxonMobil. We believe that we have established a strong reputation as a reliable and safe operator and that this will lead to future opportunities to acquire properties from major oil companies. In addition, many large properties in California are held by smaller independent companies that lack the resources to exploit them fully. We intend to pursue these opportunities to selectively expand our portfolio of properties.

Actively grow in the Sacramento Basin. We intend to continue to pursue an active drilling and acreage acquisition program in the Sacramento Basin. In 2007, our net production in the basin was 2,708 MBOE, up 38% from our net production there in 2006. We expect to continue our growth in this area, which we believe has significant exploration, exploitation and development opportunities. As one of the largest operators in the basin, we believe that we are well positioned to identify and exploit these opportunities. In particular, as discussed above, we have initiated a hydraulic fracturing program targeting the Forbes and deeper formations, a program that could result in significant reserve and production growth in the basin.

Exploration and exploitation of unconventional reservoirs. We plan to use the expertise we have developed with the fractured Monterey shale formation and other complex, unconventional reservoirs in our acquisition, exploration, exploitation and development of properties with similar characteristics. As of December 31, 2007, we controlled approximately 50,000 net acres with proven, probable and possible Monterey reserves and are actively seeking additional acreage.

Continue to focus on the California market. Historically, we have focused primarily on properties onshore and offshore California. We believe the California market will continue to provide us with attractive growth opportunities. Many properties in California are characterized by significant hydrocarbons in place with multiple pay zones and long reserve lives—characteristics that our technical expertise makes us well-suited to exploit. In addition, competition for the acquisition of properties in California is limited relative to many other markets because of the state's unique operational and regulatory environment. We believe that our technical capabilities, environmental record and experience with California regulatory requirements will allow us to grow in the California market.

Reduce per-unit production expenses. We expect our production expenses to decrease on a per BOE basis for 2008 as a whole as a result of production volume increases in the Sacramento Basin, the West Montalvo and Manvel fields and the Hastings complex, and a reduction in activity at the Hastings complex. We continue to focus on our operating cost structure in order to improve production and processing efficiencies and reduce operational downtime.

Maintain financial flexibility. We believe that maintaining both financial flexibility and a disciplined capital expenditure program are integral to the successful execution of our business strategy. Our cash flow from operations is supported by the hedges we have in place from 2008 through 2011. Using primarily purchased floors and collars, we maintain a balanced oil and natural gas derivative position intended to limit downside price risk. We will continue to pursue our hedging strategy in order to protect our ability to execute our capital expenditure plan. See "Quantitative and Qualitative Disclosures About Market Risk" for a summary of our derivative/hedging activity.

Coastal California

South Ellwood Field. The South Ellwood field is located in state waters approximately two miles offshore California in the Santa Barbara channel. We conduct our operations in the field from platform Holly and own related onshore processing facilities. We acquired our interest in the field from Mobil Oil Corporation in 1997. Since that time, we have made numerous operational enhancements to the field, including redrills, sidetracks and reworks of existing wells and upgrades at the platform and the onshore treatment facility. We operate the field and have a 100% working interest.

The South Ellwood field is approximately seven miles long and is part of a regional east-west trend of similar geologic structures running along the northern flank of the Santa Barbara channel and extending to the Ventura basin. This trend encompasses several fields that, over their respective lifetimes, are each expected to produce over 100 million barrels of oil, according to the California Division of Oil, Gas, and Geothermal Resources. The Monterey formation is the primary oil reservoir in the field, producing sour oil with a gravity of approximately 21 degrees. As of December 31, 2007, there were 18 producing wells and three injection wells in the field. During the fourth quarter of 2007, average net production at the field was 2,587 Bbl/d of oil and 1,351 Mcf/d of natural gas.

We are currently pursuing the permits necessary for a full-field development project at South Ellwood, including an extension of the current field area. The project is expected to include new wells to be drilled to the proposed lease extension area, the installation of a crude oil pipeline and workovers and redrills within the existing lease area. All drilling activities would be conducted from the existing platform. We expect to receive a draft of the environmental impact report relating to the project in the first half of 2008 and, subject to the receipt of final approvals, to commence work in 2009.

Our processing and transportation facilities at South Ellwood include a common carrier pipeline, an onshore facility, a pier and a marine terminal. We conduct two-phase separation on the drilling platform and the oil/water emulsion is transported by pipeline to the onshore facility for further separation. The oil is then transported to the marine terminal via the common carrier pipeline. From the marine terminal, the oil is transported by barge. Title to the oil is transferred when the barge completes delivery. At this time, the barge is the only means available to us for delivery of oil produced from the field. The barge is owned and operated by a third party with whom we have a long-term service contract. We sell oil production from the field to the operator of a refinery in Long Beach, California pursuant to a contract that provides for a price based on a fixed differential to the NYMEX price for light sweet crude. Pursuant to the agreement, we expect to have access to an alternate barge to make deliveries of oil production from the field when the barge we currently use is out of service and are currently in the process of obtaining the consents and approvals required prior to our use of the alternate barge. Natural gas produced at the field is transported by common carrier pipeline.

Santa Clara Federal Unit. The Santa Clara Federal Unit is located approximately ten miles offshore in the Santa Barbara channel near Oxnard, California. Our operations in the unit are conducted from two platforms, platform Gail in the Sockeye field and platform Grace in the Santa Clara field. We acquired our interest in the unit and the associated facilities from Chevron in February 1999. Production is transported via pipeline to Los Angeles, California. We operate the unit and have a 100% working interest.

The Sockeye field structure is a northwest/southeast trending anticline bounded to the north and south by fault systems. The field produces from multiple stacked reservoirs ranging from the Monterey, at about 4,000 feet, to the Upper Juncal at approximately 12,000 feet. Other formations include the Upper Topanga, Lower Topanga and Sespe. As of December 31, 2007, there were 17 producing wells and eight injection wells in the field. The oil produced from the Monterey and Upper Topanga is sour with gravities ranging from 12 to 18 degrees. The Lower Topanga and Sespe horizons produce sweet crude with gravities of 26 to 30 degrees. During the fourth quarter of 2007, average net production at the field was 3,561 Bbl/d of oil.

Chevron shut in production at platform Grace in 1997, and we currently use it as a launching and receiving facility for pipeline cleaning devices and as an interconnecting pipeline to transport oil and natural gas produced from platform Gail to our onshore plant. In 2007, we pursued a program to return platform Grace to production but had limited success with the three wells we redrilled there. We have currently suspended drilling on the platform pending further geologic and engineering review.

A third party has an option to purchase or lease platform Grace for use as a liquid natural gas, or LNG, terminal. The option became exercisable on January 1, 2008 and will expire on March 1, 2012. If the option is exercised, we will cease any exploration, exploitation and development activities then conducted from the platform and the option holder will commence construction of its LNG facility. The option holder's right to exercise the option is subject to, among other things, its receipt of certain regulatory approvals relating to the construction and operation of its LNG facility and the satisfaction of certain financial requirements. If the option is exercised, the option holder will pay us an annual fee during the period in which the LNG facility is being constructed. This annual fee will initially be $6.0 million, and will increase over time to a potential maximum of $10.0 million. Following the commencement of operations at the facility, the option holder will pay us an annual fee based on the amount of LNG processed, produced or stored at the facility. The fee will be equal to approximately $12.0 million for the first 800,000 MMBtu/d and $0.04 per MMBtu for volumes in excess of 800,000 MMBtu/d on an average annual basis.

West Montalvo. We acquired the West Montalvo field in Ventura County, California in May 2007. We operate the field and have a 100% working interest. The field, which includes an offshore portion that is reachable from onshore locations, produces from the Sespe formation. As of December 31, 2007, there were 27 producing wells in the field. During the fourth quarter of 2007, average net production at the field was 649 Bbl/d of oil and 342 Mcf/d of natural gas. Since acquiring the field, our activities have focused on returning idle wells to production, working over and recompleting existing wells, and upgrading well lift systems and processing facilities. We believe this field provides us with significant development opportunities. During 2008, we anticipate drilling two to three development wells and continuing the field reactivation program. We also expect to commission a seismic survey for the field that will assist us in designing and optimizing what we anticipate may be a significant infill development drilling program.

Dos Cuadras Field. The Dos Cuadras field is located in federal waters approximately five miles offshore California in the Santa Barbara channel. We acquired our 25% non-operated working interest in the western two-thirds of the field from Chevron in February 1999. We have working interests ranging from approximately 17.5% to 25% in the associated onshore facility and pipelines. The field is operated by an unaffiliated third party. Production is transported via pipeline to Los Angeles, California. As of December 31, 2007, there were 97 producing wells and 16 injection wells in the field. During the fourth quarter of 2007, average net production at the field was 591 Bbl/d of oil and 694 Mcf/d of natural gas.

Onshore Coastal California. Our onshore properties in the coastal California region include the Beverly Hills West field, the Santa Clara Avenue field and the Cat Canyon field. The Beverly Hills West field is located in Beverly Hills, California. All drilling and production operations at the field are conducted from a 0.6 acre surface location adjacent to the campus of Beverly Hills high school. We acquired our interest in the field in 1995. We operate the field and have a 100% working interest. The Santa Clara Avenue field is located in Ventura County, California. We acquired our interest in this field in 1994 and 1996. We operate the field and have working interests ranging from 43% to 100%. The Cat Canyon field, which we acquired in December 2007, is located in Santa Barbara County, California. We operate the field and have a 100% working interest. During the fourth quarter of 2007, aggregate average net production from our onshore coastal California properties was 430 Bbl/d of oil and 338 Mcf/d of natural gas.

Sacramento Basin

In terms of historical production, the Sacramento Basin is one of California's most prolific onshore natural gas producing areas not associated with oil production. It is approximately 210 miles long and 60 miles wide and contains a variety of different geologic plays. We own 3D seismic data covering approximately 1,000 square miles in the basin, and 2D seismic data covering approximately 20,000 line miles. We continue to analyze this data to identify additional exploration, exploitation and development opportunities on our properties. We believe this data will also help us assess acquisition opportunities in the basin.

Willows and Greater Grimes Fields. The Willows and Greater Grimes fields are located in Colusa, Glenn and Sutter Counties north of Sacramento, California. Our combined lease position in these fields was approximately 142,000 net acres as of December 31, 2007. We operate substantially all of the fields and have a volume-weighted average working interest of 71.0% (based on production during the fourth quarter of 2007).

Natural gas production in the Greater Grimes field is from the Forbes, Kione and Guinda formations and production in the Willows field is from the Forbes and Kione formations. Depths range from 2,800 feet in the Willows field to 8,900 feet in the Greater Grimes field. There were 368 producing wells in the fields as of December 31, 2007. We have been engaged in an aggressive drilling program in these fields for the past two years. During 2007, we spudded 114 wells in these fields and completed 88 productive wells. We also completed 111 workovers and recompletions. This activity led to a 17.8% increase in production from the fields in the fourth quarter of 2007 relative to the same period in 2006. During the fourth quarter of 2007, average net production at the Willows and Greater Grimes fields was 41,882 Mcf/d of natural gas. We have identified 494 drilling locations in these fields as of December 31, 2007, of which 239 are classified as proved. In 2007, we initiated a hydraulic fracturing program in the fields targeting the Forbes and deeper formations. We tested the fracturing process on three wells in 2007, and intend to pursue the program on a larger scale in 2008.

Other Sacramento Basin. We own interests in a number of other fields in Solano, Contra Costa, San Joaquin and Colusa Counties. We operate substantially all of these fields and have a volume-weighted average working interest of 62.0% (based on production during the fourth quarter of 2007). As of December 31, 2007, there were a total of 42 producing wells in these fields. We believe that the fields will provide us with exploration, exploitation and development opportunities that are similar to those found in the Willows and Greater Grimes fields. Total average net production from these fields was approximately 9 Bbl/d of oil and 5,446 Mcf/d of natural gas during the fourth quarter of 2007.

Texas

Hastings Complex. Our largest property in Texas is the Hastings complex, which encompasses approximately 4,600 net acres located 30 miles south of Houston in Brazoria County. The Hastings complex is comprised of the West Hastings Unit, the East Hastings field and the Hastings field. We have an 89% working interest in the West Hastings Unit and 100% working interests in the East Hastings and Hastings fields. We operate the entire complex.

The Hastings complex produces light, sweet crude oil with a gravity of approximately 30 degrees and is characterized by long-life, stable production. The fields in the complex produce from multiple Miocene and Frio reservoirs at depths ranging from 2,000 to 6,100 feet. As of December 31, 2007, there were 131 producing wells in the complex. Average net production from the complex was 2,517 Bbl/d of oil and 32 Mcf/d of natural gas during the fourth quarter of 2007. In 2007, we continued our aggressive field reactivation program in the complex by returning idle wells to production, increasing the lift capacity of existing wells using larger, more efficient pumps, working over and recompleting existing wells in different producing sands, significantly upgrading surface facility fluid handling capacity and increasing water injection capabilities. In 2008, we plan to focus our efforts on additional workovers and recompletions in order to further increase production and reserves.

In November 2006, we entered into an option agreement with a subsidiary of Denbury Resources Inc. relating to a potential CO 2 enhanced recovery project in the Hastings complex. Pursuant to the agreement, Denbury will pay us a non-refundable fee of $50.0 million ($45.0 million of which has been received) for an option to acquire our interest in the West Hastings Unit, the East Hastings field and certain related property for use in an enhanced recovery project in which we will have a continuing interest. Denbury may not exercise the option until September 2008. The initial exercise period will end in October 2009, subject to Denbury's right to extend it for successive one-year periods until 2016 for an annual extension fee of $30.0 million.

Following the exercise of the option, Denbury will either purchase the properties subject to the option or, if we so elect, enter into a volumetric production payment or similar arrangement with us with respect to the properties. The purchase price or volumetric production payment will be based on the value of the properties as 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. The $50.0 million option payment will not be deducted from the purchase price or payment amount. Contemporaneously with its exercise of the option, Denbury will commit to a development plan for the properties that will call for it to make capital expenditures of at least $178.7 million over five years. As part of the plan, Denbury will be responsible for providing the necessary CO 2 . Following the exercise of the option, we will retain an overriding royalty interest of 2.0% in production from the properties. We will also have the right to back in to a working interest of approximately 22.3% in the CO 2 project after Denbury recoups (i) its operating costs relating to the project and a portion of the purchase price and (ii) 130% of its capital expenditures made on the project. Denbury will either resell the properties to us at a discount or make additional payments to us if recovery operations do not meet certain development milestones by the third anniversary of the date the option exercise is given effect. During the term of the option, we will not enter into or amend any agreement in a manner that would have a material adverse effect on Denbury's rights under the option agreement. Each of us and Denbury will have a right of first refusal with respect to any proposed sale or transfer by the other of its interests under the option agreement. The option agreement also establishes an area of mutual interest with respect to us and Denbury in specified areas adjacent to the properties. We will continue our operations on the properties until the option is exercised. We cannot assure you that Denbury will exercise the option or that any CO 2 enhanced recovery project will be pursued. The success of any CO 2 enhanced recovery project that may be pursued will be subject to numerous risks and uncertainties, including those relating to the geologic suitability of the properties for such a project and the availability of an economic and reliable supply of CO 2.

Manvel. We acquired the Manvel field in Brazoria County, Texas, and certain related properties, in April 2007. We operate the field and have a 100% working interest. The field produces from the Frio sands. As of December 31, 2007, there were 35 producing wells in the field. During the fourth quarter of 2007, average net production at the field was 548 Bbl/d of oil and 193 Mcf/d of natural gas. We believe that the field provides us with exploitation and development opportunities that are similar to those in the Hastings complex, which is nearby and geologically similar.

Constitution Field. The Constitution field is located in Jefferson County, Texas. We operate part of the field and have working interests ranging from 25% to 100%. The field produces oil with a gravity of 47.8 degrees and natural gas from the Yegua reservoir at depths ranging from 13,500 feet to 15,300 feet. As of December 31, 2007, there were three producing wells in the field. During the fourth quarter of 2007, average net production from the field was approximately 17 Bbl/d of oil and 74 Mcf/d of natural gas. In 2008, we plan to drill at least one development well in this field.

Other. Our other Texas properties encompass approximately 17,700 net acres in the southern Gulf Coast region. We operate substantially all of our production in these fields and have a volume-weighted average working interest of 75.6% (based on production during the fourth quarter of 2007). As of December 31, 2007, there were a total of 58 producing wells in these fields. Total average net production from the fields in the fourth quarter of 2007 was 189 Bbl/d of oil and 3,713 Mcf/d of natural gas. In 2007, we drilled four productive development wells in these fields (two in our AWP field, one in our Barbers Hill field and one in our Giddings field).


CEO BACKGROUND

J.C. "Mac" McFarland has been a director of Venoco since June 2004. He has 30 years of experience in the oil and natural gas industry with McFarland Energy, Inc., a NASDAQ-listed company, where he was CEO from 1991 until its sale in 1997. Since 1997, he has been a consultant with McFarland Advisors, Inc. He served on the boards of NYSE-listed Huntway Refining from 1988 to 2001 and privately-held Gotland Oil, Inc. from 2000 to 2001. He was President of the California Independent Petroleum Association from 1996 to 1998. Mr. McFarland earned a degree in finance and accounting from the University of California at Berkeley and is a certified public accountant.

Joel L. Reed has been a director of Venoco since August 2005 and currently serves as our lead independent director. He previously served as a director of Venoco from September 1998 to March 2002. Starting in 1994, Mr. Reed was a partner of a predecessor entity of, and later co-founded, Relational Group, an investment banking firm that included Relational Investors and Relational Advisors. In late 2005, Relational Advisors separated from Relational Group and became RA Capital Advisors, a member of RA Capital Group. Mr. Reed currently serves as RA Capital Group's lead principal. He is also a founder of two private equity firms, Titan Investment Partners and HRA Real Estate Management I LLC. Mr. Reed was the CFO and later President and CEO of Wagner & Brown Ltd. of Midland, Texas, a privately owned group of companies engaged in energy, real estate, manufacturing, agribusiness and investment services, from 1984 to 1994. From 1981 to 1984, Mr. Reed was a member of the founding group of Ensource, Inc., a NYSE-listed company, as well as its controller and CFO. A graduate of Oklahoma State University, Mr. Reed holds bachelor's and master's degrees in accounting and is a certified public accountant (inactive).


Other Directors

J. Timothy Brittan has been a director of Venoco since May 2003 and has 25 years experience in the oil and natural gas industry. He has served as the President of Infinity Oil & Gas, Inc., an exploration and production company, since July 1989. Mr. Brittan attended the Colorado School of Mines.

Timothy M. Marquez co-founded Venoco in September 1992 and served as our CEO and as a director from our formation until June 2002. He founded Marquez Energy, a privately-held exploration and production company, in 2002 and served as its CEO until we acquired it in March 2005. Mr. Marquez returned as our Chairman, CEO and President in June 2004. Mr. Marquez has a B.S. in petroleum engineering from the Colorado School of Mines. Mr. Marquez began his career with Unocal Corporation, where he worked for 13 years managing assets offshore California and in the North Sea and performing other managerial and engineering functions.

Dr. Myles W. Scoggins has been a director of Venoco since June 2007. He has served as President of Colorado School of Mines, an engineering and science research university with strong ties to the oil and gas industry, since June 2006. Dr. Scoggins retired in 2004 after a 34-year career with Mobil Corporation and Exxon Mobil Corporation, where he held senior executive positions in the upstream oil and gas business. From 1999 to 2004 he served as Executive Vice President of Exxon Mobil Production Co. Prior to the merger of Mobil and Exxon in 1999, he was President, International Exploration & Production and Global Exploration and a member of the executive committee of Mobil Oil Corporation. He is also a member of the Board of Directors of Questar Corporation and Trico Marine Services, Inc., and a member of the National Advisory Council of the U.S. Department of Energy's National Renewable Energy Laboratory.

Mark A. Snell has been a director of Venoco since December 2006. He is the Chief Financial Officer of Sempra Energy, a San Diego-based, Fortune 500 energy-services holding company. He previously served as Group President of Sempra Global and, before that, as Vice President of Planning and Development of Sempra Energy. Before joining Sempra Energy in 2001, he served as CFO of Earth Tech, a water management, engineering and environmental services firm, CFO of Dames and Moore, an international engineering firm, Chief Financial and Administrative Officer for Latham & Watkins, a worldwide law firm, and a Senior Manager at KPMG Peat Marwick. Mr. Snell has a bachelor's degree in accounting from San Diego State University and is a certified public accountant. He is a director of San Diego Gas & Electric Company, Southern California Gas Company and Pacific Enterprises, each of which is a direct or indirect subsidiary of Sempra Energy.

Richard S. Walker has been a director of Venoco since June 2007. Mr. Walker is currently Executive Vice President and Managing Director of the Houston office of DHR International, a leading retained executive search firm headquartered in Chicago. Prior to entering the executive search industry in 2005, Mr. Walker was Managing Director in the Global Natural Resources Group of JPMorgan Chase & Co. in that firm's Houston office. Mr. Walker joined a predecessor to JPMorgan Chase & Co. in 1994 as Vice President in the Global Oil & Gas Group and was promoted to Managing Director in 1997. During his years with JPMorgan Chase & Co., Mr. Walker served as an investment banking coverage officer directing relationships with a variety of energy firms operating across all industry segments including exploration and production, service and supply, pipeline and midstream operations as well as power generation, transmission and distribution. Prior to joining JPMorgan Chase & Co. Mr. Walker worked from 1990 through early 1994 with NationsBank (the predecessor of Bank of America), both in Houston and in London. From 1981 through early 1990, Mr. Walker worked for JPMorgan Chase & Co. and a predecessor of that firm, Texas Commerce Bank, in Houston. Mr. Walker is a 1980 graduate of Loyola University, New Orleans with Bachelor of Business Administration and a 1981 graduate of Bowling Green State University, Ohio with a Masters of Business Administration. Mr. Walker is a non-practicing certified public accountant.

MANAGEMENT DISCUSSION FROM LATEST 10K

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. Pursuit of this strategy has led to increases in our oil and natural gas production and our proved reserves in each of the past three years. Our average net production increased from 11,555 BOE/d in 2005 to 17,349 BOE/d in 2006 (calculated as described in footnote 2 to the table included in "—Results of Operations") and to 19,535 BOE/d in 2007. Our proved reserves increased from 47.6 MMBOE at December 31, 2005 to 87.9 MMBOE at December 31, 2006 and to 99.9 MMBOE at December 31, 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 exploration, exploitation and development 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 exploration, exploitation and development capital expenditures, including amounts accrued and unpaid at December 31, 2007, were $310.1 million in 2007, up from $189.2 million in 2006, and we expect that they will be approximately $235.0 million in 2008. We expect to spend approximately 55% of the budgeted amount on projects in the Sacramento Basin, 30% in the Coastal California region and 15% in Texas. Included in the budget is $25.0 million for exploration projects. The aggregate levels of capital expenditures for 2008, 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 capital spending program in 2007 and 2008:

Coastal California—Exploitation and Development

In the coastal California area, we drilled five new wells in 2007 (including one higher impact exploration well), all of which were productive. We also performed eleven workovers and recompletions. In 2008, we plan to drill three wells and perform five workovers and recompletions in the area. Our primary focus is on development activities in the West Montalvo field. Since acquiring the field in May 2007, we have drilled one well and initiated an aggressive workover, recompletion and return to production program on existing wells, a program that included eight workovers in 2007. We plan to continue the program in 2008 and to drill two to three new development wells in the field, including one offshore well (which will be drilled from an onshore location). We also plan to commission a seismic survey to assist in designing and optimizing an infill development program.

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. We are also continuing to evaluate a possible expansion of our horizontal and multi-lateral well drilling activities to the Monterey formation in the field. In the Santa Clara field, we pursued a plan to return platform Grace to production in 2007, redrilling three wells with limited success. Further drilling from the platform has been suspended pending additional geologic and engineering review.

In the South Ellwood field, the permitting process continues for our full-field development project. Key components of the project include an extension of our current field area (which would effectively double the size of the existing field) and the installation of an onshore oil transport pipeline to replace the existing barge. Development of the extended lease area can be accomplished from our existing platform, platform Holly. We anticipate receiving the draft environmental impact report for this project in the first half of 2008 with project approval and startup expected in 2009.

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 drilled 122 wells in the basin in 2007 (80% of which were productive) and performed 113 workovers and recompletions. Of the 122 completed wells, 60 were drilled to non-proved locations and are therefore considered "exploratory wells" as defined in SEC Regulation S-X; we consider two of those wells to be higher-impact exploration wells. We currently have five drilling rigs and five workover/completion rigs working in the basin and expect to drill over 110 new wells and perform more than 125 workovers and recompletions there in 2008. As of December 31, 2007, we had identified 520 drilling locations in the basin, and we anticipate identifying additional locations as we pursue exploitation and development opportunities there.

We continue to test and evaluate potential downspacing opportunities in the basin as well as new methods of improving productivity and reducing drilling costs. In particular, we have initiated a hydraulic fracturing program targeting the Forbes and deeper formations, a program that could potentially enhance production and reserves significantly. The strategy of using hydraulic fracturing to enhance oil and natural gas production and recovery is a well established and proven process, although we have not used it in our existing completions and, to our knowledge, it has not been widely used in the basin by other operators. We initiated a fracture stimulation program by testing the process on three wells in November 2007. Although the production history on the three test wells is limited, early indications of the potential from fracturing are encouraging. We currently plan to perform between 20 and 50 fractures in 2008, but this estimate could change significantly depending on the success of the program. As of December 31, 2007, our acreage position in the basin had grown to approximately 193,000 net acres (236,000 gross).

Texas—Exploitation and Development

In Texas, we drilled nine new wells in 2007, all of which were productive, and performed 253 workovers and recompletions. In 2008, we plan to drill five wells and perform over 150 workovers and recompletions there.

Our focus in Texas has been on the redevelopment of the Hastings complex. This program has consisted principally of returning idle wells to production, increasing the lift capacity of existing wells, working over and recompleting existing wells in different producing sands, significantly upgrading surface facility fluid handling capacity and increasing water injection capabilities. In addition, we drilled five infill replacement wells in the Hastings complex in 2007, targeting unswept and undepleted sands. In 2008, we expect to continue our workover and recompletion program in an effort to further increase production and reserves. We also will focus on lowering operating expenses in 2008 as we reduce our remediation and redevelopment activities at the complex.

We also initiated a workover and recompletion program in the Manvel field, which produces from the same formation and exhibits operating characteristics that are similar to those of the Hastings complex. In 2007, we performed 23 workovers and recompletions and focused on upgrading facilities to handle greater production volumes. In 2008, we plan to accelerate our workover program and to drill up to three development wells. Our plans in Texas for 2008 also include drilling two to three additional development wells in some of our other fields to demonstrate and assess new exploitation opportunities.

Higher Impact Exploration Activities

In addition to the exploitation and development activities described above, we devoted approximately $14.4 million to higher impact exploration activities in 2007, including $5.8 million on drilling. We generally consider a well to be a higher impact exploration well when it is either a new field wildcat or a new-pool test (i.e., a well on a structural feature or other type of trap already producing oil or natural gas but outside the known limits of the producing area). We drilled three higher impact exploration wells in 2007, all of which were productive. In 2008, we expect to drill as many as fifteen higher impact exploration wells, including ten in the Sacramento Basin, three in Coastal California and two in Texas. We generally pursue higher impact exploration activities in areas where we have a strong operating base, proprietary knowledge and a well-established land position.

Acquisitions and Divestitures

West Montalvo and Manvel Acquisitions. We acquired the West Montalvo field in Ventura County, California in May 2007 for approximately $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.

TexCal Transaction. We acquired TexCal Energy (LP) LLC on March 31, 2006 for $456.8 million in cash. In order to finance the purchase price for the acquisition and related transaction costs of approximately $14.4 million, we borrowed approximately $119.5 million under our revolving credit facility and $350.0 million under our second lien term loan facility.

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, including several transactions in each of 2005, 2006 and 2007.

Trends Affecting our Results of Operations

Expected Production. We expect that the execution of our capital expenditure program in 2008 will result in increases in our average net production from each of our operating areas. Our coastal California properties, which produced 3.0 MBOE during 2007 (of which 93% was oil), will continue to be the largest contributor of production in 2008. At our newest coastal California property, the West Montalvo field, we expect the drilling and workover/recompletion programs we began there in 2007 to result in production increases in 2008. In the Sacramento Basin, we intend to continue our multi-year drilling program and plan to drill approximately 110 new wells and perform over 125 workovers and recompletions. In the Hastings complex, we expect further production increases in 2008 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, which we acquired in April 2007, we are implementing a similar redevelopment program to increase production by upgrading our fluid handling and injection capacity and performing several workovers and recompletions. 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."

Production Expenses. Production expenses averaged $16.74 per BOE in 2007 compared to $15.09 per BOE in 2006. The 2007 production expenses reflect our continued workover program in the Hastings complex and operating expenses from the West Montalvo and Manvel fields, where expenses increased as remedial efforts accelerated in both fields. These efforts, coupled with a production curtailment at West Montalvo for facility vessel inspections and repairs, resulted in an increase in production expenses per BOE. We expect our production expenses to decrease on a BOE basis for 2008 as a whole due to reduced remedial activities in the Hastings complex and production volume increases from the Sacramento Basin, the West Montalvo and Manvel fields and the Hastings complex. Our expectations with respect to future per-unit expenses are based in part on the projected increases in our production and are subject to numerous risks and uncertainties, including those described and referenced in the preceding paragraph.

General and Administrative Expenses. General and administrative expenses were $3.85 per BOE in 2007, excluding per BOE charges under SFAS 123R of $0.61. This represented a decrease from per BOE G&A costs of $4.41 (excluding SFAS 123R charges of $0.47) in 2006. The change resulted from an overall increase in G&A costs in the 2007 period being more than offset by production growth and the effect of an increase in the G&A costs that were capitalized as a result of being directly related to our development, exploitation, exploration and acquisition efforts. Excluding SFAS 123R charges, we expect our 2008 G&A costs to be similar to our full year 2007 costs on a per BOE basis. As with production expenses, our expectations in this regard are based in part on our projected increases in production, which are subject to numerous risks and uncertainties.

Unrealized Derivative Gains and Losses. Rising oil prices led to substantial unrealized commodity derivative losses in 2007, while fluctuating oil prices and lower natural gas prices led to unrealized commodity derivative gains in 2006. 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 or 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. We may incur significant gains or losses of this type in 2008 and in subsequent years. As described in the notes to the consolidated financial statements included in this report, we discontinued hedge accounting as of April 1, 2007. This may increase volatility in gains and losses of this type in subsequent periods. We may also have significant unrealized interest rate derivative gains and losses in subsequent periods due to changes in market interest rates.

Comparison of Year Ended December 31, 2007 to Year Ended December 31, 2006

Oil and Natural Gas Revenues. Oil and natural gas revenues increased $103.1 million (38%) to $377.9 million in 2007 from $274.8 million in 2006. The increase was primarily due to a 23% increase in production and a 14% increase in average sales prices as described below.

Oil revenues increased by $64.7 million in 2007 (34%) to $253.0 million compared to $188.3 million in 2006. Oil production rose 17%, with production of 3,981 MBbl in 2007 compared to 3,411 MBbl in 2006. The production increase was attributable primarily to the acquisition of the TexCal properties in March 2006, the Manvel field in April 2007 and the West Montalvo field in May 2007, and to our workover program in the Hastings complex. Our average realized price for oil increased $8.14 (15%) to $64.06 per Bbl for the period.

Natural gas revenues increased $38.4 million in 2007 (44%) to $124.9 million compared to $86.5 million in 2006. Natural gas production increased 32%, with production of 18,895 MMcf compared to 14,314 MMcf in 2006. The increase was due primarily to drilling and recompletion activities in the Sacramento Basin and production attributable to the March 2006 TexCal acquisition, offset by decreases in natural gas production at the South Ellwood field and the Santa Clara Federal Unit. Our average realized price for natural gas increased $0.57 (9%) to $6.61 per Mcf for the period.

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 2006 and 2007 reflect the settlement of contracts at prices above 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 2007 and an increase 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. The increase in amortization of derivative premiums and other comprehensive losses in 2007 reflects additional premiums paid in connection with the additional contracts outstanding in 2007 and amortization of other comprehensive losses beginning in the second quarter of 2007.

Other revenue decreased 39%, from $5.5 million in 2006 to $3.4 million in 2007. The change was primarily due to lower transportation income received from purchasers of oil production from the South Ellwood field.

Production Expenses. Production expenses increased $31.8 million (36%) to $119.3 million in 2007 from $87.5 million in 2006. The increase was primarily due to production expenses attributable to the TexCal, Manvel and West Montalvo acquisitions and an increase in the number of producing wells at other Venoco properties. On a per unit basis, costs increased $1.65 per BOE (11%) from $15.09 per BOE in 2006 to $16.74 per BOE in 2007, primarily due to remedial activities in the Hastings complex and at the Manvel and West Montalvo fields.

Transportation Expenses. Transportation expenses increased 72%, from $3.5 million in 2006 to $6.1 million in 2007. This was primarily attributable to increased transportation costs for barge deliveries. On a per BOE basis, transportation expenses increased $0.24 per BOE, from $0.61 per BOE in 2006 to $0.85 per BOE in 2007.

Depletion, Depreciation and Amortization (DD&A). DD&A expense increased $35.5 million (56%) to $98.8 million in 2007 from $63.3 million in 2006. DD&A expense per BOE rose $2.95, from $10.91 per BOE in 2006 to $13.86 per BOE in 2007. The increase was primarily due to a higher depletion expense resulting from the increase in the oil and natural gas property cost as a result of the TexCal, Manvel and West Montalvo acquisitions and the increase in oil and natural gas property costs during the year resulting from our capital expenditure program.

Accretion of Abandonment Liability. Accretion expense increased $1.4 million (54%) to $3.9 million in 2007 from $2.5 million in 2006. The increase was due to accretion from the properties acquired in the TexCal, Manvel and West Montalvo acquisitions and from new wells drilled and completed in the second half of 2006 and in 2007.

General and Administrative (G&A). G&A expense, net of amounts capitalized, increased $3.5 million (12%) to $31.8 million in 2007 from $28.3 million in 2006. The increase resulted primarily from increases in our professional staff and related infrastructure costs, non-recurring charges of $1.3 million for the settlement of employment contracts in 2007 and a $1.6 million increase in non-cash SFAS 123R share based compensation expense in 2007. These increases were partially offset by an increase in the G&A costs that were capitalized for payroll and related overhead for activities that are directly related to our development, exploitation, exploration and acquisition efforts. On a per BOE basis, G&A expenses decreased $0.42 (9%), from $4.88 in 2006 to $4.46 in 2007.

Financing Costs and Other. Financing costs and other increased $40.4 million (76%) to $93.4 million in 2007 from $53.2 million in 2006. Interest expense, net of interest income, increased $11.3 million (23%) from $48.8 million in 2006 to $60.1 million in 2007. The increase was primarily due to an increase in average debt outstanding in 2007. Amortization of deferred loan costs increased $0.4 million, from $3.8 million in 2006 to $4.2 million in 2007, because the 2007 total reflects a full year of amortization of loan costs related to our second lien term loan facility compared to nine months of amortization in 2006 (the debt was initially incurred on March 31, 2006). Changes in the fair value of our interest rate swap derivative instruments resulted in unrealized losses of $0.6 million in 2006 and $17.2 million in 2007. The change between years is the result of an increase in the notional amount of debt covered by the interest rate swap and a decrease in estimated interest rates used to determine the fair value of the derivative instruments. We incurred a loss on extinguishment of debt of $12.1 million in the second quarter of 2007 when we prepaid the prior second lien term loan facility and replaced it with the new term loan facility. We paid a premium of $3.5 million and wrote off related deferred loan costs of $8.6 million in connection with the prepayment of the prior term loan facility.

Income Tax Expense. The loss before taxes in 2007 resulted in an income tax benefit of $46.2 million compared to income tax expense of $15.6 million in 2006.

Net Income (Loss). Our net loss for 2007 was $73.4 million compared to net income of $24.0 million in 2006. The change between periods is the result of the items discussed above.

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005

Oil and Natural Gas Revenues. Oil and natural gas revenues increased $83.7 million (44%) from $191.1 million in 2005 to $274.8 million in 2006. The increase was primarily due to production attributable to the TexCal acquisition and higher realized oil prices, partially offset by a 1% decrease in production from other Venoco properties. The decline in production volumes from other Venoco properties was the result of (i) the effect of our sale, on March 31, 2005, of the Big Mineral Creek field in Grayson County, Texas (which averaged net production of 547 BOE/d in the first quarter of 2005), (i) high initial production rates in early 2005 from new offshore oil wells which had recently come on line at that time and (iii) the effect of maintenance projects in the third quarter and early fourth quarter of 2006, which limited production volumes in those periods.

Oil revenues increased by $53.7 million (40%) from $134.6 million in 2005 to $188.3 million in 2006. Oil production rose 16%, with production of 3,411 MBbl in 2006 compared to 2,953 MBbl in 2005. The production increase was attributable to the TexCal properties acquired in March 2006, partially offset by an 8% decline in production volumes from other Venoco properties. The decline in production from other Venoco properties resulted from the factors discussed above. Our average realized price for oil increased $10.26 (22%) to $55.92 per Bbl for the period.

Natural gas revenues increased $30.0 million (53%) from $56.5 million in 2005 to $86.5 million in 2006. Natural gas production increased 89%, with production of 14,314 MMcf compared to 7,588 MMcf in 2005. The majority of the increase was due to production attributable to the TexCal properties acquired in March 2006. Production increased approximately 15% as a result of increased production from other Venoco properties. The increased production from other Venoco properties relates to our ongoing field development activities. Our average realized price for natural gas decreased $1.41 (19%) to $6.04 per Mcf for the period.

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 2005 and 2006 reflect the settlement of contracts at prices above 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 2006 and a net 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. The increase in amortization of derivative premiums and other comprehensive losses in 2006 reflects additional premiums paid in connection with the additional contracts outstanding in 2006. The decrease in total commodity derivative losses in 2006 resulted primarily from the non-recurrence in 2006 of the significant increases in commodity prices that occurred in 2005.

Other revenue increased 23%, from $4.5 million in 2005 to $5.5 million in 2006. This increase was primarily due to revenues of $2.3 million from a pipeline we acquired in the fourth quarter of 2005.

Production Expenses. Production expenses increased $33.5 million (62%) from $54.0 million in 2005 to $87.5 million in 2006. The increase was primarily due to production expenses attributable to the TexCal properties acquired in March 2006 and a 9% increase in production expenses from other Venoco properties. The increase in production expenses for other Venoco properties relates to an increase in the number of producing wells, normal variances of timing of production expenses, including expenses relating to periodic maintenance projects, and increased costs of third party services. On a per unit basis, costs increased $2.28 per BOE, from $12.81 per BOE in 2005 to $15.09 per BOE in 2006. A significant part of this increase was attributable to remedial work projects performed in the Hastings complex in the second half of the year. Per unit production expenses attributable to the TexCal properties rose from $14.02 per BOE in 2005 to $17.34 per BOE in 2006 primarily as a result of those projects. In addition, production expenses on a per unit basis for other Venoco properties increased 11% in 2006 due primarily to increased costs of services.

Transportation Expenses. Transportation expenses increased 36%, from $2.6 million in 2005 to $3.5 million in 2006. This was primarily attributable to volume increases. On a per BOE basis, transportation expenses decreased $0.01 per BOE, from $0.62 per BOE in 2005 to $0.61 per BOE in 2006.

Depletion, Depreciation and Amortization (DD&A). DD&A expense increased $41.6 million (192%) from $21.7 million in 2005 to $63.3 million in 2006. DD&A expense rose $5.77 per BOE, from $5.14 per BOE in 2005 to $10.91 per BOE in 2006. The increase was primarily due to a higher depletion expense resulting from the increase in oil and natural gas property costs as a result of the March 2006 TexCal acquisition and an increase in future development costs.

Accretion of Abandonment Liability. Accretion expense increased $0.8 million (45%) from $1.8 million in 2005 to $2.5 million in 2006. The increase was due to accretion from the acquired TexCal properties and from new wells drilled and completed in 2006.

General and Administrative (G&A). G&A expense increased $12.3 million (77%) from $16.0 million in 2005 to $28.3 million in 2006. G&A expense rose $1.09 per BOE (30%), from $3.79 per BOE in 2005 to $4.88 per BOE in 2006. The increase resulted primarily from increases in our professional staff and related infrastructure costs, non-cash SFAS 123R share based compensation expense of $2.8 million in 2006, $1.0 million in direct costs related to Sarbanes-Oxley compliance activities and other indirect costs for internal systems and process conversions, and $0.5 million in expenses related to TexCal transition and integration activities.

Financing Costs and Other. Interest expense, net of interest income, increased $35.1 million (257%) from $13.7 million in 2005 to $48.8 million in 2006. Amortization of deferred loan costs increased $2.0 million (115%) from $1.8 million in 2005 to $3.8 million in 2006. We incurred $0.5 million in unrealized losses in 2006 from changes in the fair value of our interest rate swap derivative instruments as a result of a decrease in estimated interest rates used to determine the fair value of the derivative instruments. The changes were primarily due to debt incurred in March 2006 to acquire TexCal.

Income tax expense. Income tax expense in 2006 was $15.6 million compared to $10.3 million for 2005. The change was due to an increase in income. Our effective tax rate decreased from 40.0% for 2005 to 38.6% for 2006 due to an increase of business activity in lower taxing jurisdictions.

Net Income. Net income for 2006 was $24.0 million as compared to net income of $16.1 million in 2005.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

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 CO 2 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.

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.

CONF CALL

Mike Edwards

Hello everyone, I’m Mike Edwards with Venoco. Venoco issued a press release today in our third quarter 2008 results, we also filed our third quarter forms 10Q at the SCC. On the call today to discuss the third quarter results, we have Venoco’s Chairman and CEO Tim Marquez; CFO Tim Ficker and other members of the Venoco management team.

Before we get underway, allow me to make a couple of comments regarding forward looking statements. All statements made in this conference call, other than statements of historical fact are forward looking statements within the meaning of section 27A of the securities act, 1933. And section 21E of the securities exchange act in 1934. These statements are subject to a wide range of business risks and uncertainties including adverse developments in financial markets and general economic conditions.

Any number of factors could cause actual results to differ materially from those presented 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 activity. The possibility of delays in completing production, treatment and transportation facilities. Difficulty obtaining third party services including transportation and higher than expected production costs and other expenses.

The SEC permits oil and gas companies to disclose their filings within their filings with SEC only prove reserves, which are reserve estimates that theological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Estimates of unproved or 2P reserves, which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the company.

Forward looking statements made about the Hastings Complex and the contract with Danbury Resources are subject to business risk and uncertainties not in Venoco’s control including but not limited to the purchase price and Venoco’s use of proceeds; the implementation of a CO2 flood, and the production results and reserved if the flood is implemented. Information regarding results from hydraulic fracturing program in the Sacramento Basin is based on results to-date, which are preliminary and future results may differ.

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 the risks and uncertainties relating to forward looking statements are set forth on our filings with the Securities and Exchange Commission, including under the heading risk factors in our annual report on form 10K for the year-ended December 31st, 2007.

The earnings release and the relevant non-GAAP reconciliations are available on the investor relations page of the Venoco web site, which is www.venocoinc.com. Now I’d like to introduce Venoco’s Chairman and CEO Tim Marquez.

Tim Marquez

Thanks, Mike and welcome to everybody’s that called into the webcast. I’m very pleased today to review Venoco’s third quarter results, before I get into details, I’d just like to make a few observations about the market. I know I’m not telling anybody anything new here when I say capital markets are bit in disarray, and of course credit markets are tough right now.

The good news is, we have no current needs to access them. None of our term-debts instruments mature until late 2011. Our senior credit facility is relatively small, about $200 million. And our bank groups appeared very solid and borrowing base conservative, Tim Ficker will talk more about that later.

In addition, we’re expecting significant cash-inflows early next year related to sale of our Hastings Field to Danbury.

On the cash-flow front, prices have been volatile but a significant portion of our oil and gas our ahead. Our 2009 oil floors averaged about $58 with CAPS around $74 a barrel. On the gas side, our 2009 floors averaged over 785 per MCF and CAPS are at 1140 per MCF.

Finally, we’re reducing our 2009 capital budget to $300 million and we have the flexibility to reduce it much further should it become prudent. Talk a little bit more about our reductions here in a little bit.

So take-aways, we have no plans to access the markets at present. The Hastings sales proceeds will provide due-leverage and we have significant flexibility to adjust our capital spending and we have plenty of hedges to protect against erosion of commodity prices.

So I’ll dive right in now a little more detail starting with production. Our average daily production for the quarter was 21, 949 barrels of oil equivalent per day, which as we discussed in our second quarter conference call, was up as expected from our first half average of 21,030 BOE per day.

We have scheduled downtime in the second quarter we estimated affected second quarter production by about 500 BOE per day. We expect production to increase in the fourth quarter, we remain on target to hit our forecast for full-year 2008 of more than 21,500 BOE per day.

Report of production for the third quarter was up 6% year-over-year in third quarter 2007. While year-to-date reported production is up 10% compared to the 2007 period.

With third quarter CapEx expenditures, we’re $66.7 million, with approximately 61% spend in the Sac-Basin 19%, spend in Southern California, and 13% Texas. For the first nine months of this year, our capital expenditures were $210 million, which puts our pegs slightly below our forecast for the year of $300 million.

Moving to operating expenses and G&A costs, third quarter leaks operating expenses were 1789 per BOE, which is an increase of 16% from second quarter of 1540. An increase in third quarter expansion is primarily due increase work over activity in our Sockeye Field and higher powered costs in Texas. We also had additional property tax in California.

Third quarter GNA expenses were 507 per BOE, down from the 636 we saw in the second quarter, although that number included a one time charge we incurred when we withdrew our application to form an MLP. Excluding non-cash FAS-123 charges our G&A in the third quarter is 450 per BOE compared to 439 in the second quarter, excludes a one time MLP charge and the non-cash FAS charges.

Tim Ficker will give you additional detail in expense later in the call, now we’ll move to operations. Starting in Southern California, the Westman Tobol Field (ph) field, we’ve seen production increase nearly 50% year-to-date as a result of our ongoing effort to (inaudible) wells to production. Up side in our lift capacity and upgrading service facility. So things are going quite well there.

We continue to convert certain wells to water injection, which allows us to handle the additional water volumes from our field revitalization. In addition to well work products, late in the quarter we initiated drilling in field wells that bottomed beneath the on shore portion of the field. Keep in mind, this is the field that straddles the coastline and last year we drilled wells to the off shore portion and these wells now are going to the on shore.

We expect the first of these wells to perforated and online by the end of this month. We pushing back our plans to do a 3D seismic survey over the acreage until sometime next year.

Moving offshore, the water flood and Sockeye Field at platform continues to perform quite well and we are seeing gross oil rates around 5,520 barrels a day. I’ll remind you from last quarter’s call that first reserved report after required the asset 99 predicted by now, we’d be down about 2,300 barrels a day, so the bulk of that difference you can see is the water (inaudible) has been quite successful.

We did have some expensive work over in the quarters, unwell to dual completions, which pushed production expenditures much higher for the quarter, so those are generally non-reoccurring costs there.

In the South Ellwood Field, we completed some facilities where we’re concluding the installation of a new crane that will benefit existing operations, as well as our project to expand the lease boundary. As we mentioned on the second quarter call, the State Lands Commission released a draft EIR to public in June and we provided comments to the commission by the due date late in August. Now the state lands commissions is working to finalize EIR taken into count all of the comments they’ve received.

We don’t anticipate a final EIR until after the first of the year, so early 2009. So the earliest we can be in front of the State Lands Commission, the lead agency here, is February of 2009. After approval by the State Lands Commission, other jurisdictions, primarily the county of Santa Barbara and the City of Goleta can schedule hearings.

We believe the approval process can be completed by mid-2009. Afterwards, the project would be ready for immediate start up. The first item in the project is construction of a 10-mile on shore pipeline, along with facilities at our on shore processing plant and on platform Holly. Actually drilling from the platform could commence after some of the facilities in the pipeline work or completed, which we hope will be in the latter half of 2009.

The development program consists of wells drilled in the eastern portion of the field, as well as the current least bit portion of the field. Using our existing platform and extended reach drilling technology. Again I emphasize that the project actually reduces infrastructure on the coast by replacing the barging operation that currently transports our crude oil to market. It will be replaced with a pipeline.

The new pipeline will connect to existing segment of all American pipeline that Exxon Las Flores Canyon facility. Maturing pipeline ride-aways an anticipation to approval to projects continues and we’re initiating certain capital expenditures to long-wait items.

Moving to Texas, we some effects from downtime related to Hurricane Ike in mid-September. We had no major damage but did have power poles and lines down throughout our Hastings and Mandeville fields. Although we were able to get power restored from the utility companies in a little over a week, we weren’t able to get back to full-production by the end of the quarter. Our focus in both fields continue to be returning wells to production, converting gas as well as electrical submersible pumps and then adding fluid processing injection capacity.

In Hastings, due the pending sale to Danbury, we’ve focused on projects that maximize reserves. We’ve been very pleased with the work in these two fields this year, so everything really continues to go quite well there.

We’re working with Danbury resources regarding their purchases of the Hastings field and the implementation of a CO2 enhanced recovery project. Danbury exercises option to purchase the Hastings field and we continue to meet regularly with our technical staff on CO2 development plan. And to coordinate our activities in the field and prep for the closing on February 2nd, 2009.

Unless we reach an alternate agreement with Danbury by December 1st, we look to the formula in agreement to determine the sales price. As a reminder, the formula calculates a present value discounted at 10% for the field, based on the total proved reserve from our year-end 2008 reserve report. Using a five-year nine (inaudible) strip as a 12/31/08 for prices and other factors relating to operating expenses. As a reminder in our investor presentation October 1st, we gave some indications of the sales value would be of Hastings at different pricing areas.

As an alternative to taking cash, we may elect to receive a volume metric production payments plus some cash. We continue to evaluate these two options based on credit market conditions, commodity prices and other factors. Regardless, if we take cash in the VPP, we will retain an overriding royalty interest of 2% in the properties. The deeper rights and back into a working interest of approximately 22% in the CO2 project after Denbury various costs and expenses.

As we said previously, the backing is very valuable to us. We think ultimately reserves net to Venoco related to the backing could be upward of 30 million barrels, which is significantly more than we’re selling to Denbury in the aforementioned sale.

Manvel Field presents a similar opportunity as Hastings of CO2 flooding potential because of its similar reservoir and crude characteristics. We’re currently designing a potential CO2 flood at Manvel and exploring potential CO2 sources.

Moving back to Northern California and Sacramento Basin, everything continues to go quite well in Sacramento Basin. Our activity levels remain very high where we continue to drill in field wells in the greater Grimes and Willows fields. We have five drilling rigs and five work over completion rigs working the basin but at 84 well, completed 61 wells, and performed 98 work overs and recompletions in the first nine months. For the full-year, we expect to drill about 120 new wells, perform 125 work overs and recompletions.

In addition to recompletions, we continue the hydraulic factory program that we’ve been discussing through the year. Today we fraced 47 wells through the first nine months and we’re very encouraged by the initial success of the program, which began less than 12 months ago. We’re still on pace to perform about 75 fracs in the basin this year. We’ve also implemented multi-stage fracs, which we expect will enhance the efficiency of the overall program.

We’re working to understand all the signs and makes of various formation and pace these fracs the best. On the fracs that have been successful, we’ve seen the average IP several times higher than the pre-frack rate. Some of the successful fracs have been on wells an considered to be depleted.

We’ve added to our acreage position in the basin and now have more than 200,000 net acres. During the third quarter, we started 25 wells, performed 43 work overs and recompletions. Production is up in the third quarter by almost 1.2 million cubic feet a day second quarter and up over 10 million, that’s 23% compared to third quarter 2007.

All in all, as I said before, everything is going quite well in Sacramento Basin and continue to see more opportunities, continue to see improved performance from the frac, so still just as excited as ever before. And still, we’ve talked a little bit about the Glenda (ph). We expect to be doing some work on the Glenda in the fourth quarter in terms of fracing to see if we can unlock the potential there.

On the exploration front, on the second quarter call, we talked about some of our exploration efforts. We continue to see the longer term strategy to discover new fields and expose companies to prospects with larger upside. We continue to build acreage positions in several basins new to Venoco to play to our core competencies as well as expanding our position in Sacramento Basin. All told, we have about a half-a-million acres in various prospects and various stages in the process. The situation, particularly basins, is still competitive so we won’t go into too much detail in those.

On the specific initial drilling targets we’ve identified, we’re continuing the permitting process and the plan’s sped up to two wells by year end. One of the wells we expect to spout here in a couple weeks is another prospect in the Pacific Northwest that we discussed in some detail in our last call. We do like to say this is not the Columbia Basin.

This is much shallower towards the coast, Astoria Basin, and so we’re pretty excited about the large potential here. Well departers on the well into Pata County Texas (ph), it was spouted late in the third quarter, which is successful, would be run by our local Houston office.

Moving to the 2009 capital budget, as I mentioned earlier, we’re dropping our capital budget for 2009 to 300 million. Obviously in a lower price environment, acquisitions take precedent over drilling and what we’ve always done for 16 years is beef up acquisitions in low price environment and drill more when prices get higher. Not exactly a revolutionary strategy, but one of the main reasons we’re dropping our CapEx budget.

The splits among our various operating regions are roughly the same as the original budget. This budget should allow us to achieve production in the 20,000 to 21,000 barrels per day range for 2009, about a 10% growth rate pro forma for the sale of Hastings. I want emphasize again, that’s 20,000 to 21,000 net of the sale of Hastings. This budget allows us to maintain our current level of activity in the Sacramento Basin, demands of South Ellwood fuel field development project and continue our Monterrey and Pacific Northwest exploration programs.

We also proceed with our development plans in the Manvel Montalvo field go to slower rates than originally planned. As I mentioned earlier, our budget maintains sufficient flexibility to further reduce the budget as we proceed in 2009. With that, I’d like to introduce our CFO Tim Ficker, who’ll go over our financial highlights.

Timothy Ficker

Thanks Tim. Looking at our earnings of 221 million for the third quarter I’ll note that that includes a sizeable non-cash unrealized gain for our commodities derivatives, about 210 million after tax, which resulted from the significant swing in commodity prices from June 30th to September 30th. When we adjust for that as well as the non-cash gain on interest rate derivatives, we generated adjusted earnings of $11 million for the third quarter.

Our adjusted EBITDA was down from 84 million in the second quarter to 71 million in the third quarter. And both our adjusted earnings and our adjusted EBITDA were impacted by builds in our inventories, which reduced reported revenues and higher production expenses. I’ll give a little more detail on those shortly.

Oil and gas revenues were $158 million for the third quarter, which represents a 5% decrease over the second quarter. That decrease was driven by a production and commodity prices where we saw a decrease in our realized oil price of about $5.30 per barrel and decrease in realized gas price of about $1.50 for MCF compared to the second quarter. It was also driven by a decrease in our sales volume.

Now, here’s where I want to give a little color on our inventory build during the quarter. Our revenues are obviously a function of the commodity prices we received and the volumes that we sell as contrasted with the volumes that we produce. Typically we don’t have a significant difference between our sales volumes and our production volumes.

During the third quarter, our oil inventory grew by around 88,000 barrels, which means that we produced more barrels than we sold. As a result, our reported revenues for the quarter were reduced by about 7.2 million to reflect revenues for only the volumes sold. This inventory build during the quarter was largely driven by oil shipment delays, including delays in picking up oil produced from our South Ellwood field, which resulted from our plant maintenance events on the barge that transports that oil. And we expect the majority of the inventory impact to reverse in the fourth quarter.

Our production expenses increased about 28% in the second quarter to about 42 million in the current quarter. And I’ll remind everyone that our production expenses are composed of lease operating expenses and production and property taxes. And during the third quarter we incurred increased LOE as a result of the higher power cost in Texas as well as the additional work over activities as Tim mentioned earlier in our Sockeye Field.

With respect to our production and property taxes, we recognized additional property taxes in California as a result of our increased development program as well as increases in property value. Now the additional taxes that we recognized in the third quarter include catch-up supplemental investments of between a million-and-a-half and $2 million that we don’t expect to see again in the fourth quarter.

Turning to G&A, the G&A decreased to $10 million in the third quarter from 12 million in the second quarter, resulting primarily from $2.7 million non-cash write-off for the deferred MLP cost that we recognized in the second quarter, which is partially off-set by additional cost associated with special staff and relate infrastructures made to accommodate our growth.

On a BOE basis, our G&A expenses excluding FAS 123R charges and the non-cash write-offs were 450 for the third quarter compared to 439 for the second quarter. Commodity derivatives gains loss is the other significant part of our income statement. And as a result of the significant downward movement in oil prices between quarters, we recognize the pre-tax gain in this category of 303 million for the quarter. And of that amount, 339 million was due to unrealized change in fair value and that was partially off-set by $34 million of realized losses and $1.6 million of non-cash amortization (inaudible) of our commodity derivative premiums.

Turning to the balance sheet, the biggest changes there were our PP&E, which was up as a result of our CapEx program and some small acquisitions and debt, which was up as a result in a swing in our working capital as well as our CapEx program in those small acquisitions. And then also, commodity derivatives and interest rate derivatives saw sizeable increases from year-end resulting from increasing commodity prices between year-end and 9/30, which were slightly off-set by our interest rates.

Regarding our debt, I’ll mention a couple things. First, as we previously disclosed, Lehman Commercial Paper is one of the lenders in our revolving credit facility. They’re the smallest lender in our group at about four-and-three-quarters percent of the facility. And as you can probably imagine, they’re no longer funding borrowing requests made under our revolver.

Currently we owe Lehman a little under $5 million and as a result, the availability under our $200 million borrowing base is effectively 195 million. We will continue to seek to replace Lehman in our facility; however, we don’t view the Lehman situation has a significant impact on our liquidity.

Next, I also want to point out that we believe that our borrowing base is very conservative and our asset base supports a much higher borrowing base, although we haven’t asked for our banks to increase that. So overall, I’ll reiterate what Tim said earlier. As a result of our cash on hand and the existing availability under our revolver, we don’t face any near-term liquidity issues. That’s a brief overview. Tim, I’ll turn it back to you.

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