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TABLE OF CONTENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on October 30, 2006

Registration No. 333-130478



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 5
to
Form S-1
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933

Venoco, Inc.
(Exact Name of Registrant as Specified in its Charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  77-0323555
(I.R.S. Employer
Identification No.)

370 17th Street, Suite 2950
Denver, Colorado 80202-1370
(303) 626-8300
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)

Timothy Marquez
Chairman and Chief Executive Officer
370 17th Street, Suite 2950
Denver, Colorado 80202-1370
(303) 626-8300
(Name, address, including zip code, and telephone number,
including area code, of agent for service)



Copies to:
John Elofson, Esq.
Davis Graham & Stubbs LLP
1550 Seventeenth Street, Suite 500
Denver, Colorado 80202-1500
(303) 892-9400
  Seth R. Molay, P.C.
J. Michael Chambers, Esq.
Akin Gump Strauss Hauer & Feld LLP
1111 Louisiana Street, 44th Floor
Houston, Texas 77002
(713) 220-5800

        Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable following the effectiveness of this registration statement.

        If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 (the "Securities Act"), check the following box. o

        If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE


Title of Each Class of Securities
to be Registered

  Proposed Maximum
Aggregate Offering
Price(1)

  Amount of
Registration
Fee(2)


Common Stock, par value $0.01 per share   $402,500,000   $43,068

(1)
Estimated solely for the purpose of computing the amount of the registration fee in accordance with Rule 457(o) under the Securities Act.

(2)
Previously paid.

        The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.




The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED OCTOBER 30, 2006

12,500,000 Shares

Logo

Common Stock


                We are selling 10,000,000 shares of common stock and the selling stockholders, one of which is a family trust controlled by our Chief Executive Officer, are selling 2,500,000 shares of our common stock.

                Prior to this offering, there has been no public market for our common stock. The initial public offering price of the common stock is expected to be between $19.00 and $21.00 per share. We have applied to list our common stock on The New York Stock Exchange under the symbol "VQ."

                The underwriters have an option to purchase from us and the selling stockholders a maximum of 1,875,000 additional shares to cover over-allotments of shares.

                We intend to use the net proceeds from our sale of common stock in this offering to repay outstanding borrowings under our credit facilities. Affiliates of certain of the underwriters are lenders under our credit facilities and will therefore receive a portion of those proceeds.

                Investing in our common stock involves risks. See "Risk Factors" on page 15.

 
  Price to Public
  Underwriting
Discounts and Commissions

  Proceeds to
Venoco, Inc.

  Proceeds to
Selling
Stockholders

Per Share   $   $   $   $
Total   $   $   $   $

                Delivery of the shares of common stock will be made on or about                    ,         .

                Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse   Lehman Brothers   JPMorgan

 

 

 
A.G. Edwards   BMO Capital Markets

The date of this prospectus is                    ,         .



TABLE OF CONTENTS

 
ABOUT THIS PROSPECTUS
SUMMARY
RISK FACTORS
USE OF PROCEEDS
DIVIDEND POLICY
CAPITALIZATION
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
UNAUDITED PRO FORMA FINANCIAL INFORMATION
SELECTED FINANCIAL DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
BUSINESS AND PROPERTIES
MANAGEMENT
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PRINCIPAL AND SELLING STOCKHOLDERS AND BENEFICIAL OWNERSHIP OF MANAGEMENT
DESCRIPTION OF CAPITAL STOCK
SHARES ELIGIBLE FOR FUTURE SALE
DESCRIPTION OF INDEBTEDNESS
UNDERWRITING
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS FOR NON-UNITED STATES HOLDERS
LEGAL MATTERS
EXPERTS
WHERE YOU CAN FIND MORE INFORMATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
GLOSSARY OF TECHNICAL TERMS


ABOUT THIS PROSPECTUS

        You should rely only on the information contained in this prospectus. Neither we nor the selling stockholders have authorized anyone to provide you with information different from that contained in this prospectus. We and the selling stockholders are offering to sell shares of our common stock and are seeking offers to buy shares of our common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is complete and accurate only as of the date on the front cover regardless of the time of delivery of the prospectus or of any sale of shares.

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SUMMARY

        This summary highlights information appearing in other sections of this prospectus. It is not complete and does not contain all of the information you should consider before investing in our common stock. We urge you to read this entire prospectus to understand more fully the considerations that may be important to you in making your decision regarding an investment in our common stock, including the "Risk Factors" section beginning on page 15. We use the term "pro forma" in this prospectus to refer to information presented after giving pro forma effect to (i) our acquisition of TexCal Energy (LP) LLC, or TexCal, on March 31, 2006 and (ii) our incurrence of $469.5 million of indebtedness to finance that acquisition, transactions that we refer to collectively as the TexCal transaction.


Our Company

        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. We believe that California's numerous large oil and natural gas fields and limited number of well capitalized, independent operators present us with an attractive niche market opportunity. Our principal properties are located offshore southern California, onshore in California's Sacramento Basin and along the Gulf Coast of Texas, and are characterized by long reserve lives, predictable production profiles and substantial opportunities for further exploitation and development, including numerous relatively low risk drilling locations.

        We have grown to become one of the largest independent oil and natural gas companies in California based on production volumes. In furtherance of our growth strategy, we acquired TexCal for $456 million in cash on March 31, 2006. As a result of the transaction, we have strengthened our position as the most active driller in the Sacramento Basin, a principal growth area for us, and have reestablished our presence in Texas. According to reserve reports prepared by Netherland, Sewell & Associates, Inc., or NSAI, and DeGolyer & MacNaughton, we had proved reserves of approximately 94.5 MMBOE as of July 31, 2006, of which 57% were oil and 57% were proved developed. The PV-10 value of our proved reserves as of that date was approximately $1.7 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 "Non-GAAP Financial Measures and Reconciliations" beginning on page 12. Our average net production for the second quarter of 2006 was 17,114 BOE/d, implying a proved reserves to production ratio of 15.1 years. The following table summarizes certain information concerning our production for the second quarter of 2006 and our reserves and inventory of drilling locations as of July 31, 2006:

 
  Second Quarter
2006
Production

  Proved Reserves
   
 
  Average
Net Production
(BOE/d)

  % Oil
  Total
(MMBOE)

  % Oil
  PV-10 Value
($MM)

  Drilling
Locations(2)

Coastal California(1)   8,564   90 % 42.5   87 % $ 934.0   68
Sacramento Basin   5,923     28.5     $ 381.6   509
Texas   2,627   85 % 23.5   72 % $ 385.3   60
   
 
 
 
 
 
Total   17,114   58 % 94.5   57 % $ 1,700.9   637
   
 
 
 
 
 

(1)
Includes properties offshore and onshore southern California.

(2)
Represents total gross drilling locations identified by management as of July 31, 2006. Of the total, 373 locations are classified as proved.

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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. Fields of this type often have a significant number of potential drilling prospects. One of our primary objectives is to continue to increase the amount of oil and natural gas ultimately recovered from these fields, thereby increasing our reserves and production. Our offshore California fields and our Texas Gulf Coast fields generally have well-established production histories and exhibit relatively moderate production declines. As of July 31, 2006, our proved reserves to production ratio was 15.1 years and our proved developed reserves to production ratio was 8.6 years, in each case based on production during the second quarter of 2006. We believe that this relatively stable base of long-lived production is a strong platform to support further growth in our reserves and production.

        Attractive reserve replacement costs.    From our inception in 1992 through July 31, 2006, we made approximately $916.7 million in capital expenditures to acquire, develop and/or discover 146.3 MMBOE of proved reserves, an average reserve replacement cost (including reserve revisions) of $6.27 per BOE. These capital expenditures consisted of $558.0 million used to complete 37 acquisitions and $358.7 million used for development and exploration projects. See page 14 for a description of how we calculate reserve replacement cost.

        Significant drilling inventory and growth potential.    As of July 31, 2006, we had identified 637 drilling locations on our properties, including 422 on properties we acquired in the TexCal transaction, and we anticipate identifying additional locations on those properties as we pursue our exploitation and development activities. As of June 30, 2006, we controlled a total of 238,760 gross acres (188,621 net), including 83,502 gross acres (66,425 net) we acquired in the TexCal transaction. 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. In addition, we believe that improved technology, our experienced technical staff and our substantial acreage position will allow us to further expand our proved reserves and production through exploration activities.

        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. We were the most active driller in the basin in 2005 and we believe that, on a pro forma basis as of December 31, 2005, we had the largest acreage position in the area. We have a twelve-person team of engineers and geologists dedicated exclusively to our operations in the basin, and have access to four drilling and two workover rigs in the area. 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 discount 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 20 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

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oil and natural gas industry across a broad range of disciplines, including geology, drilling and operations, and regulatory and environmental matters. Our team currently includes 45 engineers and geoscientists. 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 94% of our June 2006 production. 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. Following Mr. Marquez's return as our CEO in June 2004, we returned to our historical strategy of actively pursuing these opportunities. Our exploration, exploitation and development capital expenditures were $23.2 million in 2004 and $83.6 million in 2005, and we expect that they will be approximately $185 million in 2006, including $83.5 million incurred in the first half of the year.

        Make opportunistic acquisitions of underdeveloped properties.    We pursue acquisitions that 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. The acquisition of TexCal, with its significant property positions in the Sacramento Basin and the Hastings complex in Texas, demonstrates our successful implementation of this strategy. 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 June 2006, our average net production in the basin was 32,438 Mcf/d, or 197% of our pro forma production in the area in November 2004. Our acreage position in the basin as of June 30, 2006 was approximately 297% of what it was in

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November 2004. 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 addition to allowing us to increase our proved reserves and production, we expect that our focus on this area will allow us to lower our per unit operating costs.

        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 June 30, 2006, we controlled approximately 63,000 net acres with proven, probable and possible Monterey reserves and are actively seeking additional acreage. We plan to spend approximately $18 million on Monterey development wells and approximately $19 million on Monterey exploration in 2006.

        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 make 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 operating costs.    We intend to improve our operating margins through cost control measures and increases in production volumes, particularly with respect to operations where fixed costs comprise a large proportion of total costs. For example, a major portion of our offshore operating costs are related to fixed platform expenses. Accordingly, we believe that we can significantly increase our profitability by increasing production from those platforms.

        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 2006 through 2010. Using a blend of purchased floors and collars, we maintain a balanced oil and natural gas derivative position intended to limit downside price risk while maintaining the potential to benefit from price increases on a substantial portion of our anticipated production. We will continue to pursue our hedging strategy in order to protect our ability to execute our capital expenditure plan and to preserve upside potential. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk" for a summary of our derivative/hedging activity.


Recent Developments

        Expected Third Quarter Results.    We are in the process of preparing our Quarterly Report on Form 10-Q for the quarter ended September 30, 2006. We expect to report that our average net production in the third quarter of 2006 was approximately 16,950 BOE/d, a figure that reflects the effect of two maintenance projects that occurred during the quarter. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—Trends Affecting Our Results of Operations." We also expect to report that our production expenses for the quarter were approximately $17.26 per Bbl. This amount reflects costs associated with our remedial rework projects in the Hastings complex and the effect of the two maintenance projects. In addition, we expect to report that our general and administrative expenses were approximately $7.6 million, or $4.85 per Bbl, including approximately $500,000 in non-cash costs relating to share-based payments under FAS 123R and $600,000 in costs relating to bonus payments made in connection with certain real property interests. See "Certain Relationships and Related Transactions—Real Property Dividends and Related

4


Transactions." As described in "Business and Properties—Description of Properties—Coastal California—South Ellwood Field," we sold several shipments of oil production from our South Ellwood field during the quarter at a discount to prices we have historically received from sales of production from the field. This discount averaged approximately $15.31 per Bbl on approximately 95,000 Bbls of production, and the associated transportation costs were approximately $0.59 per Bbl higher. Average net production of oil from the field was 3,374 Bbl/d in June 2006.

        South Ellwood.    The South Ellwood field is our largest field in terms of proved reserves. Average net production from the field in June 2006 was 3,374 Bbl/d, or approximately 20% of our aggregate net production for the month. The oil produced at the field is delivered via a barge owned and operated by an unaffiliated third party. At this time, the barge is the only means available to us for delivery of oil produced from the field. From time to time this barge is unavailable due to maintenance and repair requirements. On October 20, 2006, the barge was involved in a minor collision with a tugboat and is currently out of service for repair and inspection. Because we have limited storage capacity for oil produced from the field, we have been required to significantly curtail production at the field. Although we expect that the barge will be back in operation in the first week of November 2006, if it does not return to operation as expected, we will be required to shut in production from the field. Any such shut in would adversely affect our financial condition and results of operations.

        Amendment to Revolving Credit Facility.    On October 25, 2006, we entered into an amendment to our revolving credit facility which provided for, among other things, an increase in the borrowing base from $200.0 million to $230.0 million and an increase in the interest rate applicable to amounts borrowed under the facility of 0.5%. The interest rate will decline by 0.5% following the completion of this offering if our net proceeds from the offering are at least $200.0 million. The facility as amended imposes restrictions on acquisitions of oil and natural gas assets, capital expenditures and cash dividends prior to completion of a qualifying IPO, and requires that we enter into derivative contracts covering 75% of our anticipated production in 2010 at specified prices. See "Description of Indebtedness—Revolving Credit Facility."

        TexCal Transaction.    We acquired TexCal on March 31, 2006 for $456 million in cash. According to a reserve report prepared by independent engineers DeGolyer & MacNaughton, as of December 31, 2005, TexCal had proved reserves of 31.4 MMBOE, 31.2% of which were located in the Sacramento Basin. TexCal's average net production for 2005 was 4,340 BOE/d and its average net production in the first quarter of 2006 was 5,467 BOE/d. The TexCal transaction is consistent with our strategy of acquiring large, mature fields with established reserves in our core areas of operation, and it provided us with approximately 422 additional drilling locations, of which 269 are classified as proved. The acquisition also improved our proved reserves to production ratio and allows us to better balance our mix of oil and natural gas production.

        The Sacramento Basin properties we acquired in the TexCal transaction are adjacent to our other properties in the area, and we believe that this proximity has allowed us to benefit from greater economies of scale and to leverage our technical expertise in this core area to enhance the value of the properties acquired. Because ownership of the remaining acreage in the area is relatively fragmented, we also expect to have opportunities to complete "tack-on" acquisitions with relatively limited competition. We also believe that the properties we acquired in the transaction present us with numerous exploration, exploitation and development opportunities, in part because the capital expenditures devoted to the properties have been limited in recent years. For example, in addition to opportunities to expand production at the Hastings complex through the return of idle wells to production and improvements to artificial lift systems, we believe there may be significant potential for a CO2 enhanced oil recovery project at the complex. See "Business and Properties—Description of Properties—Texas—Hastings Complex."

        We financed the acquisition through aggregate borrowings of $469.5 million under a second amendment and restatement of our existing revolving credit facility and a new senior secured second

5



lien term loan facility, which we refer to collectively as the credit facilities. We intend to use the proceeds of this offering to reduce the outstanding indebtedness under these facilities. See "Use of Proceeds."


Risk Factors

        You should carefully consider the risks described under "Risk Factors" beginning on page 15 and the other information contained in this prospectus before making a decision to invest in our common stock. The risks to which our business is subject include operating and environmental risks relating to our offshore operations, which are greater in some respects than those associated with onshore operations. In addition, in our pursuit of additional growth opportunities, we will be competing with many companies that have greater financial and technical resources than we do. Also, for the reasons described under "Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry," our ability to replace our reserves, the extent to which current estimates of our proved reserves ultimately correspond to actual production, and the time and financial and other resources required to produce our reserves are all subject to numerous risks and uncertainties, many of which are beyond our control. You should also be aware that following this offering, Timothy Marquez will beneficially own 68% of our outstanding common stock (or 65% if the underwriters exercise in full their option to purchase additional shares), and will therefore be able to control the composition of our board of directors and direct our management and policies.


Our Offices

        We were incorporated in California in 1992 and reincorporated in Delaware in 1998. Our principal office is located at 370 17th Street, Suite 2950, Denver, Colorado 80202-1370 and our telephone number is (303) 626-8300. We also maintain a corporate office located at 6267 Carpinteria Avenue, Carpinteria, CA 93013-1423. The telephone number at that office is (805) 745-2100. Our website can be found at www.venocoinc.com. The information on our website is not a part of this prospectus.


Additional Information

        As used in this prospectus, unless the context otherwise indicates, references to "Venoco," the "company," "we," "our," "ours" and "us" refer to Venoco, Inc. and its subsidiaries collectively, including TexCal and its subsidiaries from March 31, 2006. Certain oil and natural gas industry terms used in this prospectus are defined in the "Glossary of Technical Terms" beginning on page A-1. Except as otherwise indicated (i) all share and per-share information included in this prospectus reflects the stock splits described in note 1 to our financial statements beginning on page F-8 and (ii) the information in this prospectus assumes that the underwriters do not exercise their option to purchase additional shares to cover over-allotments.

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The Offering

Issuer   Venoco, Inc.

Selling stockholders

 

The Marquez Trust, a family trust controlled by Timothy Marquez, our CEO, and the Denver Foundation, a charitable foundation. See "Principal and Selling Stockholders and Beneficial Ownership of Management."

Common stock offered by us

 

10,000,000 shares

Common stock offered by the selling stockholders

 

2,500,000 shares

Underwriters' option to purchase additional shares

 

We and the selling stockholders have granted the underwriters a 30-day option to purchase up to an additional 1,875,000 shares of common stock.

Common stock outstanding after this offering

 

42,692,500 shares

Use of proceeds

 

We estimate that our net proceeds from this offering will be approximately $184.5 million after deducting estimated discounts, fees and expenses (including fees and expenses related to sales by the selling stockholders).

 

 

We intend to use the net proceeds from this offering to reduce outstanding indebtedness under our credit facilities.

 

 

We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders. See "Use of Proceeds." Affiliates of certain of the underwriters are lenders under our credit facilities and will therefore receive a portion of the net proceeds of this offering. See "Underwriting."

New York Stock Exchange symbol

 

VQ

Risk factors

 

An investment in our common stock involves a high degree of risk. See "Risk Factors" and other information included in this prospectus for a discussion of factors you should consider before investing in our common stock.

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Summary Historical and Pro Forma Financial Information

        The following table presents summary historical and unaudited pro forma financial information for the periods indicated. The summary historical financial information for each of the years in the three-year period ended December 31, 2005 was derived from our audited financial statements and the summary historical financial information for the six-month periods ended June 30, 2005 and 2006 was derived from our unaudited interim financial statements. The audited financial statements for each of the years in the three-year period ended December 31, 2005 and the unaudited financial statements for the six-month periods ended June 30, 2005 and 2006 are included elsewhere in this prospectus. In the opinion of management, our unaudited interim financial statements reflect all adjustments necessary to present fairly our financial position at June 30, 2005 and 2006 and our income and cash flows for the six-month periods ended June 30, 2005 and 2006. All such adjustments are of a normal recurring nature.

        The summary pro forma financial information for the year ended December 31, 2005 and the six-month period ended June 30, 2006 gives effect to the following transactions as if they had occurred on January 1, 2005:

    our acquisition of TexCal; and

    the related incurrence of $469.5 million of indebtedness under the credit facilities.

        Because the TexCal transaction was completed on March 31, 2006, the summary pro forma information for the six-month period ended June 30, 2006 reflects pro forma information for the quarter ended March 31, 2006 and historical information for the quarter ended June 30, 2006.

        The summary historical and unaudited pro forma financial information set forth below is not necessarily indicative of future results. We urge you to read the summary financial information set forth below in conjunction with the audited and unaudited financial statements included in this prospectus, the information contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Unaudited Pro Forma Financial Information" included elsewhere in this prospectus. All data other than per share data is shown in thousands.

 
  Historical
   
   
 
 
  Pro Forma
 
 
  Year ended December 31,
  Six Months ended June 30,
 
 
  Year ended December 31,
2005

  Six Months ended June 30,
2006

 
 
  2003
  2004(5)(6)
  2005
  2005
  2006
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

  (Successor)

  (Successor)

 
Statement of Operations Data:                                            
  Oil and natural gas revenues   $ 109,754   $ 139,961   $ 191,092   $ 87,390   $ 127,374   $ 273,428   $ 155,654  
  Commodity derivative losses—realized     (10,272 )   (17,589 )   (22,870 )   (7,155 )   (12,789 )   (26,080 )   (12,576 )
  Commodity derivative losses—unrealized         (1,096 )   (34,725 )   (27,999 )   (14,977 )   (31,750 )   (14,920 )
  Other revenues(1)     5,253     5,457     4,456     2,091     3,380     5,525     3,581  
   
 
 
 
 
 
 
 
    Total revenues     104,735     126,733     137,953     54,327     102,988     221,123     131,739  
  Production expenses     45,617     49,567     54,038     24,282     35,518     76,239     42,051  
  Transportation expense     2,785     2,915     2,596     1,216     1,610     2,768     1,655  
  Depreciation, depletion and amortization     16,161     16,489     21,680     9,493     23,497     55,381     32,599  
  Accretion of abandonment liability     1,401     1,482     1,752     1,018     1,111     2,279     1,278  
  General and administrative expenses, net of capitalized amounts     11,632     11,272     16,007     7,699     12,121     19,982     13,654  
  Litigation settlement expense(2)     6,000                          
  Amortization of deferred loan costs     370     3,050     1,755     1,021     1,471     4,785     2,408  
  Interest expense, net     2,125     2,269     13,673     6,820     18,629     56,445     28,935  
  Income taxes     7,876     16,088     10,300     774     3,600     1,000     3,650  
  Minority interest in Marquez Energy         95     42     42         42      
  Cumulative effect of change in accounting principle, net of tax(3)     (411 )                        
   
 
 
 
 
 
 
 
  Net income     11,179     23,506     16,110     1,962     5,431     2,202     5,509  
  Preferred stock dividends     (8,465 )   (7,134 )                    
  Excess of carrying value over repurchase price of preferred stock(4)         29,904                      
   
 
 
 
 
 
 
 
  Net income applicable to common equity   $ 2,714   $ 46,276   $ 16,110   $ 1,962   $ 5,431   $ 2,202   $ 5,509  
   
 
 
 
 
 
 
 
                                             

8


Basic earnings per common share:                                            
  Income before cumulative effect of change in accounting principle   $ 0.07   $ 1.33   $ 0.49   $ 0.06   $ 0.17   $ 0.20   $ 0.17  
Cumulative effect of change in accounting principle     0.01                          
   
 
 
 
 
 
 
 
  Total   $ 0.08   $ 1.33   $ 0.49   $ 0.06   $ 0.17   $ 0.20   $ 0.17  
   
 
 
 
 
 
 
 
Diluted earnings per common share:                                            
  Income before cumulative effect of change in accounting principle   $ 0.07   $ 0.48   $ 0.49   $ 0.06   $ 0.16   $ 0.07   $ 0.16  
Cumulative effect of change in accounting principle     0.01                          
   
 
 
 
 
 
 
 
  Total   $ 0.08   $ 0.48   $ 0.49   $ 0.06   $ 0.16   $ 0.07   $ 0.16  
   
 
 
 
 
 
 
 
Cash Flow Data:                                            
  Cash provided (used) by                                            
    Operating activities   $ 31,557   $ 43,309   $ 39,931   $ 28,221   $ 60,370              
    Investing activities     (10,531 )   (27,990 )   (58,695 )   (46,047 )   (531,262 )            
    Financing activities     (23,333 )   30,979     (26,562 )   (31,228 )   474,890              
Other Financial Data (unaudited):                                            
  Adjusted EBITDA(7)   $ 38,122   $ 62,498   $ 98,243   $ 48,069   $ 68,914   $ 151,563   $ 89,330  
  Capital expenditures     9,064     21,829     90,106     32,809     86,774              

 


 

June 30, 2006

 
  Historical
  As Adjusted(8)
 
  (Successor)

   
Balance Sheet Data (end of period):            
  Cash and cash equivalents   $ 13,387   $ 13,387
  Plant, property and equipment, net     743,223     743,223
 
Total assets

 

 

853,299

 

 

853,299
  Long-term debt, excluding current portion     658,777     474,277
  Stockholders' equity     5,287     189,007

(1)
Other revenues primarily include amounts received from purchasers of our oil production to reimburse us for transportation and barge expenses.

(2)
Amount comprises settlement costs incurred by us in connection with a lawsuit brought by Mr. Marquez asserting wrongful termination and breach of contract. See "Certain Relationships and Related Transactions—Ownership and Related Disputes and Transactions—Filing of Marquez Actions."

(3)
The amount shown for 2003 is the cumulative effect of change in accounting principle of $411,000, net of tax. On January 1, 2003, we adopted SFAS 143, "Accounting for Asset Retirement Obligations," which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Pursuant to our adoption of SFAS 143, we recognized a credit during the first quarter of 2003 of $411,000, net of tax, for the cumulative effect of the change in accounting principle. See note 13 to our financial statements.

(4)
Amount comprises the excess of the carrying value over the repurchase price of the mandatorily redeemable convertible preferred stock plus accrued and unpaid dividends net of unamortized issuance costs.

(5)
Marquez Energy is included in our statements of operations, balance sheet and cash flow data from July 2004, when common control between our company and Marquez Energy was established. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Accounting Matters—Acquisition of Marquez Energy" and note 1 to our financial statements.

(6)
Mr. Marquez's percentage beneficial ownership in our common stock increased from approximately 94% to 100% on December 22, 2004, the date we effected a merger with a corporation the sole stockholder of which was the Marquez trust. Accordingly, Mr. Marquez's basis in our assets has been "pushed-down" as of the date of the merger, meaning that our post-transaction financial statements reflect Mr. Marquez's basis in our assets (the successor basis) rather than our historical basis. The aggregate purchase price has been allocated to a portion of the underlying assets and liabilities based upon their respective fair values at the date of the merger, with the values of certain long-lived assets reduced on a pro rata basis for the excess of Mr. Marquez's portion of the fair value of acquired net assets over the purchase price of the shares acquired. Due to the de minimis impact on our results of operations for the nine-day period ended December 31, 2004, the successor basis of accounting has been applied to our financial statements as of December 31, 2004, with the consolidated statements of operations, comprehensive income (loss), and cash flows for the fiscal year ended 2004 being presented on a historical, or "predecessor" basis. See note 1 to our financial statements.

9


(7)
We set forth our definition of Adjusted EBITDA and a reconciliation of net income to Adjusted EBITDA on pages 12-13.

(8)
As adjusted to reflect the issuance of 10,000,000 shares of common stock in this offering at an assumed offering price of $20.00, which is the midpoint of the range set forth on the cover page of this prospectus, and the application of the net proceeds as described in "Use of Proceeds." The amount shown does not reflect any events occurring after June 30, 2006, including the payment of certain dividends described in "Certain Relationships and Related Transactions—Real Property Dividends and Related Transactions."

10



Summary Historical and Pro Forma Operating and Reserve Information

        The following table sets forth certain information regarding our average net production volumes, average sales prices realized and certain expenses associated with sales of oil and natural gas for the periods indicated on a historical and pro forma basis. We urge you to read this information in conjunction with the information contained in our financial statements and related notes included elsewhere in this prospectus. The information set forth below is not necessarily indicative of future results.

 
  Historical
   
   
 
 
  Pro Forma
 
 
  Year ended December 31,
   
 
 
  Six Months ended June 30,
2006(2)

  Year ended December 31,
2005(1)

  Six Months ended June 30,
2006

 
 
  2003
  2004(1)
  2005(1)
 
Production Volume                                      
  Natural gas (MMcf)     5,607     5,826     7,588     5,764     12,442     7,570  
  Oil (MBbl)     3,114     3,101     2,953     1,606     3,728     1,797  
  MBOE     4,049     4,072     4,218     2,567     5,802     3,059  
Daily Average Production Volume                                      
  Natural gas (Mcf/d)     15,362     15,918     20,789     42,031     33,938     41,823  
  Oil (Bbl/d)     8,532     8,472     8,090     9,982     10,104     9,928  
  BOE/d     11,092     11,125     11,555     16,987     15,760 (3)   16,899  
Oil Price per Bbl Produced (in dollars)                                      
  Realized price before commodity derivative loss   $ 26.29   $ 34.69   $ 45.66   $ 57.31   $ 47.52   $ 57.79  
  Realized commodity derivative loss     (2.39 )   (5.47 )   (7.46 )   (8.83 )   (6.49 )   (7.77 )
   
 
 
 
 
 
 
  Net realized   $ 23.90   $ 29.22   $ 38.20   $ 48.48   $ 41.03   $ 50.02  
   
 
 
 
 
 
 
Natural Gas Price per Mcf Produced (in dollars)                                      
  Realized price before commodity derivative gain (loss)   $ 5.06   $ 5.77   $ 7.45   $ 6.36   $ 7.76   $ 7.01  
  Realized commodity derivative gain (loss)     (0.50 )   (0.11 )   (0.11 )   0.24     (0.15 )   0.18  
   
 
 
 
 
 
 
  Net realized   $ 4.56   $ 5.66   $ 7.34   $ 6.60   $ 7.61   $ 7.19  
   
 
 
 
 
 
 
Average Sale Price per BOE(4)   $ 24.69   $ 30.42   $ 39.55   $ 44.15   $ 42.63   $ 46.33  
Expense per BOE                                      
  Production expenses(5)   $ 11.27   $ 12.17   $ 12.81   $ 13.84   $ 13.14   $ 13.75  
  Transportation expenses     0.69     0.72     0.62     0.63     0.48     0.54  
  Depreciation, depletion and amortization     3.99     4.05     5.14     9.15     9.55     10.66  
  General and administrative expense(6)     2.87     2.77     3.79     4.72     3.44     4.46  
  Interest expense, net(6)     0.52     0.56     3.24     7.26     9.73     9.46  

(1)
Amounts shown include Marquez Energy from July 1, 2004. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Accounting Matters—Acquisition of Marquez Energy."

(2)
Includes information for TexCal from March 31, 2006, the date of acquisition. Daily average production volumes shown represent (i) second quarter 2006 production from TexCal properties divided by 91 days plus (ii) first half 2006 production from other Venoco properties divided by 181 days.

(3)
Excludes production from the Big Mineral Creek field, which we sold in March 2005. Average net production from the field was 547 BOE/d in the first quarter of 2005, or 135 BOE/d for 2005 as a whole.

(4)
Amounts shown are based on oil and natural gas sales, net of inventory changes and realized commodity derivative losses, divided by sales volumes.

(5)
Production expenses are comprised of oil and natural gas production expenses and production taxes.

(6)
Net of amounts capitalized.

        The following table summarizes our historical estimates of net proved oil and natural gas reserves as determined by NSAI, DeGolyer & MacNaughton and our previous independent petroleum engineer,

11


Ryder Scott Company, L.P., or Ryder Scott, as of the dates indicated. NSAI provided those estimates of our reserves as of December 31, 2004 and December 31, 2005, and Ryder Scott provided the estimates of our reserves as of December 31, 2003. The estimates as of July 31, 2006 were provided by DeGolyer & MacNaughton with respect to certain of our properties and by NSAI with respect to the remainder. The pro forma column combines our historical estimated reserves as of December 31, 2005 with those of TexCal as determined by DeGolyer & MacNaughton as of that date. All proved reserve estimates were prepared using constant prices and unescalated costs in accordance with SEC guidelines based on the prices received on a field-by-field basis as of the date of the relevant report. Proved reserve estimates do not include any value for probable or possible reserves which may exist, nor do they include any value for undeveloped acreage. The proved reserve estimates represent the net revenue interest in the properties.

 
  December 31,
   
   
 
  Pro Forma
as of
December 31, 2005

  July 31,
2006

 
  2003
  2004(1)
  2005
Proved Reserves (end of period)                    
Oil (MBbl)   46,757   39,935   35,300   49,974   53,565
Natural gas (MMcf)   66,585   69,876   74,053   174,154   245,323
Total proved reserves (MBOE)   57,855   51,581   47,642   79,000   94,452
Percent proved developed reserves   69%   70%   69%   64%   57%

(1)
Does not include Marquez Energy reserves. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Accounting Matters—Acquisition of Marquez Energy."


Non-GAAP Financial Measures and Reconciliations

Adjusted EBITDA

        We use EBITDA, adjusted as described below, referred to in this prospectus as Adjusted EBITDA, as a supplemental measure of our performance that is not required by, or presented in accordance with, GAAP. We define Adjusted EBITDA as net income before (i) net interest expense, (ii) income tax expense, (iii) depreciation, depletion and amortization, (iv) amortization of deferred loan costs, (v) the cumulative effect of change in accounting principle, (vi) pre-tax unrealized gains and losses on derivative instruments and (vii) non-cash expenses relating to share-based payments under FAS 123R. We present Adjusted EBITDA because we consider it an important supplemental measure of our performance, in particular because it excludes amounts, such as expenses relating to share-based payments and unrealized gains and losses on derivative instruments, that do not relate directly to our operating performance. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.

        Adjusted EBITDA is not a measurement of our financial performance under GAAP and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted EBITDA amounts shown in this prospectus are comparable to Adjusted EBITDA amounts disclosed by other companies. In evaluating Adjusted EBITDA, you should be aware that it excludes expenses that we will incur in the future on a recurring basis.

        Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation. Some of its limitations are:

    it does not reflect our cash expenditures for capital expenditures;

    it does not reflect our significant interest expense, or the cash requirements necessary to service interest or principal payments on our indebtedness;

12


    it does not reflect the non-cash costs of our stock incentive plans, which are an ongoing component of our employee compensation program; and

    although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect the cost or cash requirements for such replacements.

        We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally. For more information, see our consolidated financial statements and the notes to those statements included elsewhere in this prospectus. The following table reconciles our net income to our Adjusted EBITDA on a historical and pro forma basis as of the dates shown (in thousands):

 
  Historical
   
   
 
  Pro Forma
 
  Year ended December 31,
  Six Months ended
June 30,

 
   
  Six Months
ended
June 30,
2006

 
   
   
  2005

  Year ended December 31,
2005

 
  2003
  2004
  2005
  2006
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

  (Successor)

  (Successor)

 
   
   
   
  (Unaudited)

  (Unaudited)

  (Unaudited)

  (Unaudited)

Net income   $ 11,179   $ 23,506   $ 16,110   $ 1,962   $ 5,431   $ 2,202   $ 5,509
Interest expense, net     2,125     2,269     13,673     6,820     18,629     56,445     28,935
Income tax expense     7,876     16,088     10,300     774     3,600     1,000     3,650
Depreciation, depletion and amortization     16,161     16,489     21,680     9,493     23,497     55,381     32,599
Amortization of deferred loan costs     370     3,050     1,755     1,021     1,471     4,785     2,408
Cumulative effect of change in accounting principle     411                        
Pre-tax unrealized losses on derivative instruments         1,096     34,725     27,999     14,977     31,750     14,920
Pre-tax share-based payments                     1,309         1,309
   
 
 
 
 
 
 
Adjusted EBITDA   $ 38,122   $ 62,498   $ 98,243   $ 48,069   $ 68,914   $ 151,563   $ 89,330
   
 
 
 
 
 
 

PV-10 Value

        The present value of future net cash flows (PV-10 value) is a non-GAAP measure because it excludes income tax effects. Management believes that before-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company's unique tax position and strategies, can make after-tax amounts less comparable. We derive PV-10 value based on the present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using prices and costs as of the date of estimate without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and income taxes, and discounted using an annual discount rate of 10%. The following table reconciles the standardized measure of

13



future net cash flows to the PV-10 value on a historical and pro forma basis as of the dates shown (in thousands):

 
  December 31,
   
   
 
  Pro Forma
as of
December 31, 2005(2)

  July 31,
2006(3)

 
  2003
  2004
  2005(1)
Standardized measure of discounted future net cash flows   $ 258,477   $ 404,052   $ 565,385   $ 939,949     1,144,998
Add: Present value of future income tax discounted at 10%     138,107     249,026     328,445     502,269     555,938
PV-10 value   $ 396,584   $ 653,078   $ 893,830   $ 1,442,218   $ 1,700,936

(1)
Based on unescalated prices of (i) $57.75 per Bbl for oil and natural gas liquids, adjusted for quality, transportation fees and regional price differentials and (ii) $10.08 per MMBtu for natural gas, adjusted for energy content, transportation fees and regional price differentials.

(2)
Amounts shown include a PV-10 value for the TexCal properties of $548,388, which amount is equal to a standardized measure of discounted future net cash flows of $374,564 plus a present value of future income tax discounted at 10% of $173,824. Information for TexCal is based on unescalated prices of (i) $61.04 per Bbl for oil and natural gas liquids and (ii) $9.44 per MMBtu for natural gas adjusted, in each case, as described in note (1) above.

(3)
The July 31, 2006 NSAI report is based on unescalated prices of $71.00 per Bbl for oil and natural gas liquids and $7.25 per MMBtu for natural gas, and the DeGolyer & MacNaughton report as of that date is based on unescalated prices of $74.40 per Bbl for oil and natural gas liquids and $7.25 per MMBtu for natural gas, adjusted, in each case, as described in note (1) above. If December 31, 2005 prices had been used as described in note (1) above, our estimated proved reserves as of July 31, 2006 would have been 93.5 MMBOE and those reserves would have had a PV-10 value of $1,666,997.


Reserve Replacement Cost

        We define the term "reserve replacement cost" to mean an amount per BOE equal to the sum of all costs incurred relating to oil and natural gas property acquisition, exploitation, development and exploration activities (as reflected in our year-end financial statements for the relevant year) divided by the sum of all additions and revisions to estimated proved reserves, including reserve purchases. The calculation of reserve additions for each year is based upon the reserve report of our independent engineers as of the end of the relevant period, and includes, where applicable, production from the date acquisitions were completed through the date of the reserve report. Management uses reserve replacement cost to compare our company to others in terms of our historical ability to increase our reserve base in an economic manner. However, our historical reserve replacement costs are not necessarily indicative of the reserve replacement costs we will incur in the future. Historical sources of reserve additions, such as acquisitions, may be more expensive or unavailable in the future. Increases in commodity prices in recent years, and corresponding increases in the market value of oil and natural gas properties, have resulted in increases in our reserve replacement costs. In addition, some companies define reserve replacement cost differently than we do, a fact that limits the usefulness of reserve replacement cost as a comparative measure in some circumstances.

14



RISK FACTORS

        You should carefully consider the risks described below and the other information in this prospectus before making a decision to invest in our common stock.

Risks Related to Our Business and the Oil and Natural Gas Industry

Oil and natural gas prices are volatile and change for reasons that are beyond our control. A decrease in oil and natural gas prices could have a material adverse effect on our business, financial condition or results of operations.

        A substantial decline in the prices we receive for our oil and natural gas production would have a material adverse effect on us, as our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon those prices. For example, changes in the prices we receive for our oil and natural gas affect our ability to finance capital expenditures, make acquisitions, borrow money and satisfy our financial obligations. In addition, declines in prices could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our reserves. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Prices have historically been volatile and are likely to continue to be volatile in the future, especially given current world geopolitical conditions. Furthermore, the oil we produce in California is generally heavier than, and therefore sells at a discount to, premium grade light oil, and the amount of that discount varies over time. The price for the heavier oil we produce is affected by factors that may not have the same impact on the price of premium grade light oil. For example, in 2005, the price of our oil was negatively affected by an increase in the supply of heavy oil from Ecuador, which increased the discount we received for our oil compared to premium grade light oil. We cannot predict how the discount will change in the future, and it is possible that it will increase. The difficulty involved in predicting the discount also makes it more difficult for us to effectively hedge our production. Transportation costs and capacity constraints can also reduce the prices we receive for our oil and natural gas production. The prices of oil and natural gas are affected by a variety of other factors that are beyond our control, including:

    changes in global supply and demand for oil and natural gas;

    commodity processing, gathering and transportation availability;

    actions of the Organization of Petroleum Exporting Countries;

    domestic and foreign governmental regulations and taxes;

    domestic and foreign political developments, including embargoes, affecting oil-producing activity;

    the level of global oil and natural gas exploration activity and inventories;

    the price, availability and consumer acceptance of alternative fuel sources;

    the availability of refining capacity;

    technological advances affecting energy consumption;

    weather conditions;

    financial and commercial market uncertainty; and

    worldwide economic conditions.

        These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements.

15



Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantity and present value of our reserves.

        The reserve data included in this prospectus represent estimates only. Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes and availability of capital, estimates of required capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves (including those attributable to the TexCal transaction) could prove to be inaccurate, and any significant inaccuracy could materially affect our future estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of our future net cash flows. Our estimated proved reserves at year-end 2004 were approximately 6.3 MMBOE lower than they were at the end of 2003. The reduction was due primarily to reclassifications of reserves as a result of new information from a pressure study conducted on one of our producing reservoirs, a reevaluation of a development plan for an expected waterflood, a contractual production constraint that was not mitigated to the extent we had expected and the depletion that occurred as we produced oil and natural gas from our properties. In addition, our estimated proved reserves at December 31, 2005 were approximately 3.9 MMBOE lower than at December 31, 2004, primarily because of the sale of our Big Mineral Creek property (partially offset by net reserve acquisitions during the year), depletion that occurred as we produced oil and natural gas from our properties and other adjustments based on reservoir information. Similar events in the future could lead to downward revisions of our reserve estimates, and those revisions could be material.

        At July 31, 2006, 43.4% of our estimated proved reserves were proved undeveloped and 5.5% were proved developed non-producing. Estimation of proved undeveloped reserves and proved developed non-producing reserves is almost always based on analogy to existing wells as contrasted with the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Revenues from estimated proved developed non-producing reserves will not be realized until some time in the future, if at all.

        You should not assume that the present values referred to in this prospectus represent the current market value of our estimated oil and natural gas reserves. The timing of the production and the expenses related to the development of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, our PV-10 estimates are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Further, the effect of derivative instruments is not reflected in these assumed prices. Also, the use of a 10% discount factor to calculate PV-10 value may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. Any significant variations from the interpretations or assumptions used in our estimates, such as increased or decreased production levels or changes of conditions and information resulting from new or reinterpreted seismic data or otherwise, could cause the estimated quantities and net present value of our reserves to change materially.

Our business involves significant operating risks that could adversely affect our production and could be expensive to remedy.

        Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including:

    well blowouts;

16


    cratering and explosions;

    pipe failures and ruptures;

    pipeline accidents and failures;

    casing collapses;

    fires;

    mechanical and operational problems that affect production;

    formations with abnormal pressures;

    uncontrollable flows of oil, natural gas, brine or well fluids; and

    releases of contaminants into the environment.

        For example, in May 2005, we encountered downhole mechanical problems during a routine workover on a well in the South Ellwood field. As a result of the problems, average net production from the well dropped from 1,155 BOE/d in April 2005 to 262 BOE/d in May 2005 before being restored to 1,309 BOE/d in December 2005. In addition, our efforts to restore production at the well required us to delay the implementation of some other projects. We may experience similar problems and delays from time to time in the future. Our offshore operations are further subject to a variety of operating risks specific to the marine environment, including a dependence on a limited number of gas and water injection wells and electrical transmission lines. For example, we are currently adding additional salt water disposal capacity in the South Ellwood field to supplement existing disposal wells. Failure to complete this project in a timely manner could result in a curtailment of production from the field. Moreover, because we operate in California, we are also susceptible to risks posed by natural disasters such as earthquakes, mudslides, fires and floods. For example, our production in the first quarter of 2006 was adversely affected by heavy rain and flooding in northern California.

        In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our operations are conducted offshore and in other environmentally sensitive areas, including areas with significant residential populations. We do not maintain insurance in amounts that cover all of the losses to which we may be subject, and insurance may not continue to be available on acceptable terms. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed. For example, our production for the third quarter of 2006 was adversely affected by maintenance activities performed at two of our fields. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—Trends Affecting Our Results of Operations."

The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not control. For our largest field, we rely on one barge, which is currently out of service, to transport production from the field. When these facilities or systems, including the barge, are unavailable, our operations can be interrupted and our revenues reduced.

        The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, transportation barges and processing facilities owned by third parties. In general, we do not control these facilities and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely impact our ability to deliver to market the oil and natural gas we produce and thereby cause a significant interruption in our operations. In some cases, our

17



ability to deliver to market our oil and natural gas is dependent upon coordination among third parties who own transportation and processing facilities we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. These are risks for which we generally do not maintain insurance.

        We are at particular risk with respect to oil produced at our South Ellwood field, which is our largest field in terms of proved reserves. Our average net production from the field in June 2006 was 3,374 Bbl/d, or approximately 20% of our aggregate net production for the month. The oil produced at the field is delivered via a barge owned and operated by an unaffiliated third party. This third party is the only company that currently has a permit to deliver oil via barge in the vicinity of the field and, at this time, the barge is the only means available to us for delivery of oil produced from the field. Our loss of the use of the barge, in the absence of a satisfactory alternative delivery arrangement, would have an adverse effect on our financial condition and results of operations.

        From time to time, the barge is unavailable due to maintenance and repair requirements. For example, it was out of service for part of August 2006 due to scheduled maintenance. In addition, on October 20, 2006, the barge was involved in a minor collision with a tugboat and is currently out of service for repair and inspection. Because we have limited storage capacity for oil produced from the field, we have been required to significantly curtail production at the field. If the barge does not return to operation in the first week of November 2006, we will be required to shut in production from the field. Any such shut in would adversely affect our financial condition and results of operations.

        As described in "Business and Properties—Description of Properties—Coastal California—South Ellwood Field," the owner of the refinery to which we have historically delivered oil production from the field informed us in August 2006 that it was unwilling to accept further deliveries from the barge. As a result, we have sold recent shipments of oil production from the field to a refinery in the San Francisco area on a shipment-by-shipment basis. However, that refinery is not obligated to accept more than two additional deliveries of approximately 53,000 Bbls each. Moreover, the average price we received from the sales to that refinery was approximately $15.31 less per Bbl than we received from previous sales, and the associated transportation costs were approximately $0.59 higher per Bbl (in each case based on sales through September 30, 2006). Any new delivery or sales arrangement may require time to implement and may require us to accept lower prices for our production and/or incur higher transportation costs. Our ability to implement a new delivery or sales arrangement may be adversely affected by the fact that there are only a limited number of refineries in California. Further, our existing storage facilities have only limited capacity. If we are unable, for any sustained period, to implement an acceptable delivery or sales arrangement, we will be required to shut in production from the field. Any such shut in, or an inability to obtain favorable terms for delivery of the oil produced from the field, would adversely affect our financial condition and results of operations. We would be similarly affected if any of the other transportation, gathering and processing facilities we use became unavailable or unable to provide services.

We may discover problems arising from the TexCal transaction for which we have no recourse against the sellers.

        We conducted a review of TexCal's business, properties, liabilities and operations prior to entering into the TexCal merger agreement. In the course of our review, we relied to a significant extent on information provided by TexCal. We did not independently verify all of the information provided to us. To the extent that information consisted of estimates, those estimates may vary from actual results. In addition, the scope of our review was not comprehensive enough to uncover all potential problems that could affect us as a result of the transaction. Accordingly, it is possible that we will discover problems with the business, properties or operations we acquired, or the liabilities we assumed, that we did not anticipate at the time we completed the transaction. These problems may be material and could include, among other things, unexpected environmental problems, title defects or other liabilities. The

18



merger agreement contained representations from TexCal concerning its business, properties, operations and liabilities, but those representations expired at the closing of the transaction. As a result, it is unlikely that we will have any recourse against the sellers if we subsequently discover inaccuracies in those representations or other liabilities arising from pre-acquisition operations of TexCal.

Acquisitions involve a number of risks, including the risk that we will be adversely affected by a failure to efficiently integrate acquired operations.

        Our ability to achieve the benefits we expect from the TexCal transaction will depend in part upon our ability to efficiently integrate TexCal's operations with ours. Our management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business concerns. The challenges involved in the integration process include retaining key employees and maintaining key employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding the TexCal properties. We will face similar risks with respect to other acquisitions we complete in the future.

        More generally, the success of any acquisition will depend on a variety of factors, including our ability to accurately assess the reserves associated with the property, future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales. The risks normally associated with acquisitions are heightened in the current environment, as market prices of oil and natural gas properties are generally high compared to historical norms. In addition, we may face greater risks to the extent we acquire properties in areas outside of California, as we did when we acquired TexCal, because we may be less familiar with operating, regulatory and other issues specific to those areas.

Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects.

        We financed the acquisition of TexCal through the incurrence of $469.5 million of indebtedness under our credit facilities. As of October 26, 2006, we had total indebtedness under the credit facilities and our 8.75% senior notes due 2011 of approximately $687.8 million, which bore interest at a weighted average rate of 9.13%. Because we must dedicate a substantial portion of our cash flow from operations to the payment of interest on our debt, that portion of our cash flow is not available for other purposes. In addition, borrowings under our credit facilities bear interest at rates that vary with changes in market rates. Accordingly, an increase in market rates could significantly increase our debt service obligations. Our ability to make scheduled principal and interest payments on our indebtedness and pursue our capital expenditure plan will depend to a significant extent on our financial and operating performance, which is subject to prevailing economic conditions, commodity prices and a variety of other factors. Our cash flow from operations and other capital resources may not be sufficient to pay the principal and interest on our debt in the future. If our cash flow and other capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay scheduled capital projects, sell material assets or operations or restructure our debt. In the event that we are required to dispose of material assets or operations, obtain additional capital or restructure our debt to meet our debt service and other obligations, the terms of any such transaction may not be favorable to us and may not be completed in a timely fashion. In addition, our credit facilities contain mandatory prepayment provisions that would limit our ability to respond to a shortfall in our expected liquidity by selling assets, issuing equity securities or incurring additional indebtedness. In particular, the facilities would require us to use some or all of the proceeds of such transactions to reduce amounts outstanding under one or both of those facilities. See "Description of Indebtedness."

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        Our level of indebtedness, and the covenants contained in the indenture governing our senior notes and the agreements governing our credit facilities, which we refer to collectively as our "debt agreements," could have important consequences for our operations, including by:

    making it more difficult for us to satisfy our obligations under our debt agreements and increasing the risk that we may default on our debt obligations;

    requiring us to dedicate a substantial portion of our cash flow from operations and from sales of assets and stock to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures, acquisition opportunities and other general business activities;

    limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other activities;

    limiting management's discretion in operating our business;

    limiting our flexibility in planning for, or reacting to, changes in commodity prices or our business, the industry in which we operate and/or commodity prices;

    impairing our ability to withstand successfully a downturn in commodity prices or our business or the economy generally;

    placing us at a competitive disadvantage against less leveraged competitors; and

    making us vulnerable to increases in interest rates.

        In addition, under the terms of our debt agreements, we must comply with certain financial and other covenants, including leverage and current ratio requirements. Our ability to comply with these covenants in future periods will depend on our ongoing financial and operating performance, which in turn will be subject to general economic conditions and financial, market and competitive factors, in particular the selling prices for our oil and natural gas and our ability to successfully implement our overall business strategy.

        The breach of any of the covenants in our debt agreements could result in a default under the applicable agreement, which would permit the affected lenders or noteholders, as the case may be, to declare all amounts outstanding thereunder to be due and payable, together with accrued and unpaid interest, and to foreclose on substantially all of our assets. In the event of an actual or potential default, we could attempt to refinance the debt or repay the debt with the proceeds from an equity offering or from sales of assets. The proceeds of future borrowings, equity financings or asset sales may not be sufficient to refinance or repay the debt. The terms of our debt agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and the value of our assets and our operating performance at the time of such offering or other financing. We may not be able to complete any such offering, refinancing or sale of assets on desirable terms or at all.

Our operations are subject to a variety of contractual, regulatory and other constraints that can limit our production and increase our operating costs, and thereby adversely affect our results of operations.

        We are subject to a variety of contractual, regulatory and other operating constraints that limit the manner in which we conduct our business. These constraints affect, among other things, the permissible uses of our facilities, the availability of pipeline capacity to transport our production and the manner in which we produce oil and natural gas. These constraints can change to our detriment without our consent. For example, effective January 2003, the terms of the sales gas transportation contract relating to the South Ellwood field were revised to reduce the permitted amount of carbon dioxide in the natural gas we transport from the field from 5% to 3%. Additionally, the method of measuring carbon

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dioxide levels was made more stringent. To comply with these new requirements, we shut in some high gas-to-oil ratio wells, which reduced our gas sales from the field from 4.2 MMcf/d in 2002 to 2.5 MMcf/d in 2003. Similar events may occur in the future. These events, many of which are beyond our control, could have a material adverse effect on our operations and financial condition and could reduce estimates of our proved reserves.

Our hedging arrangements involve credit risk and may limit future revenues from price increases and result in financial losses or reduce our income.

        To reduce our exposure to fluctuations in the prices of oil and natural gas, we enter into hedging arrangements with respect to a substantial portion of our oil and natural gas production. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk" for a summary of our hedging activity. Hedging arrangements expose us to risk of financial loss in some circumstances, including when:

    production is less than expected;

    a counterparty to a hedging contract fails to perform under the contract;

    there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received; or

    there is a sudden, unexpected event that materially impacts oil or natural gas prices.

        Our total net realized losses on derivative instruments were $10.3 million, $17.6 million and $22.9 million for the years ended December 31, 2003, 2004 and 2005, respectively, and $12.8 million for the six months ended June 30, 2006. In addition, rising oil and natural gas prices have recently caused us to incur substantial unrealized commodity derivative losses. Our total net unrealized losses on derivative instruments were $1.1 million and $34.7 million for the years ended December 31, 2004 and 2005, respectively (we had no loss in this category in 2003), and $15.0 million for the six months ended June 30, 2006. These unrealized losses resulted from the fact that some of our derivative positions do not qualify for hedge accounting treatment. Changes in the fair market value of the derivatives were therefore required to be recognized in the statement of operations. We may incur realized and unrealized losses of this type in the future. Hedging arrangements may also limit the benefit we would otherwise receive from increases in the prices for oil and natural gas. The uncertainties associated with our hedging programs are greater than those of many of our competitors because the price of the heavy oil that we produce in California is subject to risks that are in addition to the price risk associated with premium grade light oil.

        Our working capital could be impacted if we enter into derivatives arrangements that require cash collateral and commodity prices subsequently change in a manner adverse to us. Further, the obligation to post cash or other collateral could, if imposed, adversely affect our liquidity.

We may not be able to raise the capital necessary to replace our reserves.

        Reserves can be replaced through acquisitions of new properties or the exploration, exploitation and development of existing properties. Either approach requires substantial capital, and capital may not always be available to us on reasonable terms or at all. If our cash flow from operations and cash available from other sources is less than we anticipate, we may not be able to finance the capital expenditures, or complete the acquisitions, necessary to replace our reserves. A reduction in our reserves could, in turn, further limit the availability of capital, as the maximum amount of available borrowing under the revolving credit facility is, and the availability of other sources of capital likely will be, based in part on the estimated quantities of our proved reserves.

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Oil and natural gas exploration, exploitation and development activities may not be successful and could result in a complete loss of a significant investment.

        Exploration, exploitation and development activities are subject to many risks. For example, new wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. Similarly, previously producing wells that are returned to production after a period of being shut in may not produce at levels that justify the expenditures made to bring the wells back on line. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. We endeavor to utilize the knowledge of the fractured Monterey shale formation we have developed in our offshore drilling operations in onshore exploratory drilling, and our assumptions about the consistency of this formation may not be correct. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The cost of exploration, exploitation and development activities is subject to numerous uncertainties beyond our control, and cost factors can adversely affect the economics of a project. Further, our development activities may be curtailed, delayed or canceled as a result of numerous factors, including:

    title problems;

    problems in delivery of our oil and natural gas to market;

    pressure or irregularities in geological formations;

    equipment failures or accidents;

    shortages of, or delays in obtaining, equipment or qualified personnel;

    adverse weather conditions;

    reductions in oil and natural gas prices;

    compliance with environmental and other governmental requirements; and

    costs of, or shortages or delays in the availability of, drilling rigs, equipment and services.

A failure to complete successful acquisitions would limit our growth.

        Our strategy is to increase our reserves and production, in part through the acquisition of additional oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise. Our focus on the California market reduces the pool of suitable acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller or finance the acquisition. Our revolving credit agreement currently prohibits us from effecting acquisitions with an aggregate value in excess of the aggregate value of assets we sell, and in any event in excess of $15.0 million in any year, until we complete a public offering of our stock resulting in net proceeds to us of at least $200.0 million. The substantial indebtedness we incurred in the TexCal transaction will further limit our ability to make future acquisitions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations.

Competition in the oil and natural gas industry is intense and may adversely affect our results of operations.

        We operate in a competitive environment for acquiring properties, marketing oil and natural gas, integrating new technologies and employing skilled personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be willing and able to pay more for oil and natural gas properties and prospects than our financial

22



resources permit, and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects. Our competitors may also enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future with respect to acquiring prospective reserves, developing reserves, marketing our production, attracting and retaining qualified personnel, implementing new technologies and raising additional capital.

We are subject to complex laws and regulations, including environmental laws and regulations, that can adversely affect the cost, manner and feasibility of doing business.

        Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to exploration for, and the exploitation, development, production and transportation of, oil and natural gas, as well as environmental and safety matters. We cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, will not harm our business, results of operations and financial condition. Laws and regulations applicable to us include those relating to:

    land use restrictions, which are particularly strict along the coast of southern California where many of our operations are located;

    drilling bonds and other financial responsibility requirements;

    spacing of wells;

    emissions into the air (including emissions from ships in the Santa Barbara channel);

    unitization and pooling of properties;

    habitat and endangered species protection, reclamation and remediation;

    the containment and disposal of hazardous substances, oil field waste and other waste materials;

    the use of underground storage tanks;

    transportation permits;

    the use of underground injection wells, which affects the disposal of water from our wells;

    safety precautions;

    the prevention of oil spills;

    the closure of production facilities;

    operational reporting; and

    taxation and royalties.

        Under these laws and regulations, we could be liable for:

    personal injuries;

    property and natural resource damages;

    releases or discharges of hazardous materials;

    well reclamation costs;

    oil spill clean-up costs;

    other remediation and clean-up costs;

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    plugging and abandonment costs, which may be particularly high in the case of offshore facilities;

    governmental sanctions, such as fines and penalties; and

    other environmental damages.

        Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. We are a defendant in a series of lawsuits alleging, among other things, that air, soil and water contamination from the oil and natural gas facility at our Beverly Hills field caused the plaintiffs to develop cancer or other diseases or to sustain related injuries. See "Business and Properties—Legal Proceedings." If resolved adversely to us, these suits could have a material adverse effect on our financial condition. In addition, compliance with applicable laws and regulations could require us to delay, curtail or terminate existing or planned operations.

        Some environmental laws and regulations impose strict liability. Strict liability means that in some situations we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of prior operators of properties we have acquired or other third parties. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. Similarly, our plugging and abandonment obligations will be substantial and may be more than our estimates. Compliance costs are relatively high for us because many of our properties are located offshore California and in other environmentally sensitive areas and because California environmental laws and regulations are generally very strict. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters, but they will be material. In addition, our operations could be adversely affected by federal and state laws that require environmental impact studies to be conducted before governmental authorities can take certain actions, including in some cases the issuance of permits to us. Environmental risks are generally not fully insurable.

        We could also be adversely affected by existing or future tax laws and regulations. For example, proposals have been made to amend federal and California law to impose "windfall profits" taxes or other types of additional taxes on oil companies. If any of these proposals become law, our costs would increase, possibly materially. One such proposal will be presented to California voters in November 2006. This proposal would impose a severance tax on oil production from properties in California (not including those located in federal waters more than three miles offshore California). The tax rate would be determined with reference to the level of oil production and the average price of oil, with rates ranging from 1.5% to 6.0% of the price of oil produced. While the manner in which the proposal would be implemented is in some respects uncertain, its effect on us could be significant.

The loss of our CEO or other key personnel could adversely affect our business.

        We believe our continued success depends in part on the collective abilities and efforts of Timothy Marquez, our CEO, and other key personnel, including the executive officers listed in "Management—Directors and Executive Officers." We do not maintain key man life insurance policies. The loss of the services of Mr. Marquez or other key management personnel could have a material adverse effect on our results of operations. Additionally, if we are unable to find, hire and retain needed key personnel in the future, our results of operations could be materially and adversely affected.

Shortages of qualified operational personnel or field equipment and services could affect our ability to execute our plans on a timely basis, reduce our cash flow and adversely affect our results of operations.

        The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas

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industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. From time to time, there have also been shortages of drilling rigs and other field equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors can also result in significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. We have experienced some difficulty in obtaining drilling rigs, experienced crews and related services in the past year and may continue to experience these difficulties in the future. In part, these difficulties arise from the fact that the California market is not as attractive for oil field workers and equipment operators as mid-continent and Gulf Coast areas where drilling activities are more widespread. In addition, the cost of drilling rigs and related services has increased significantly. If shortages persist or prices continue to increase, our profit margin, cash flow and operating results could be adversely affected and our ability to conduct our operations in accordance with current plans and budgets could be restricted.

The geographic concentration of our operations and oil and natural gas reserves in California makes us vulnerable to localized operating and other risks.

        Most of our oil and natural gas reserves are located in California. Because our reserves are not as diversified geographically as those of many of our competitors, our business is subject to local conditions to a greater extent than other, more diversified companies. Any regional events, including price fluctuations, natural disasters and restrictive regulations, that increase costs, reduce availability of equipment or supplies, reduce demand or limit our production may impact our operations more than they would if our reserves were more geographically diversified.

Because we cannot control activities on properties we do not operate, we cannot control the timing of those projects. Our inability to fund required capital expenditures with respect to non-operated properties may result in a reduction or forfeiture of our interests in those properties.

        Other companies operated approximately 6% of our June 2006 production. Our ability to exercise influence over operations for these properties or their associated costs is limited. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital with respect to exploration, exploitation, development or acquisition activities. The success and timing of exploration, exploitation and development activities on properties operated by others depend upon a number of factors that may be outside our control, including:

    the timing and amount of capital expenditures;

    the operator's expertise and financial resources;

    approval of other participants in drilling wells; and

    selection of technology.

        Where we are not the majority owner or operator of a particular oil and natural gas project, we may have no control over the timing or amount of capital expenditures associated with the project. If we are not willing and able to fund required capital expenditures relating to a project when required by the majority owner or operator, our interests in the project may be reduced or forfeited.

Changes in the financial condition of any of our large oil and natural gas purchasers could make it difficult to collect amounts due from those purchasers.

        For the year ended December 31, 2005, 76% of our pro forma oil and natural gas revenues were generated from sales to four purchasers, ConocoPhillips, Chevron, Enserco Energy, Inc. and Shell Trading (US) Co. A material adverse change in the financial condition of any of our largest purchasers

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could adversely impact our future revenues and our ability to collect current accounts receivable from such purchasers.

Threatened or actual terrorist activity could adversely affect our business.

        The continued threat of terrorism and the impact of military or other government action in response to that threat have led to and will likely lead to increased volatility in prices for oil and natural gas and could affect the markets for the oil and natural gas we produce. Further, the U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. Oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist activities and offshore facilities could be attractive targets because of the possibility that an attack would result in significant environmental damage. Our operations would be adversely affected if infrastructure integral to our operations were destroyed or damaged. As a result of such a terrorist attack, the threat of such an attack or of terrorist activities in general, we may not be able to obtain insurance coverage at prices that we consider reasonable or at all. These developments could subject our operations to increased risk and could have a material adverse effect on our business.

We may be required to write down the carrying value of our properties and a reduction in our asset values could adversely affect our stock price.

        We may be required under full cost accounting rules to write down the carrying value of our properties when oil and natural gas prices decrease or when we have substantial downward adjustments of our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. We use the full cost method of accounting for oil and natural gas exploitation, development and exploration activities. Under full cost accounting rules, we perform a "ceiling test." This test is an impairment test and generally establishes a maximum, or "ceiling," of the book value of our oil and natural gas properties that is equal to the expected after-tax present value of the future net cash flows from proved reserves, including the effect of cash flow hedges, calculated using prevailing prices on the last day of the relevant period. If the net book value of our properties (reduced by any related net deferred income tax liability) exceeds the ceiling, we write down the book value of the properties. Depending on the magnitude of any future impairments, a ceiling test write down could significantly reduce our income or produce a loss. Ceiling test computations use commodity prices prevailing on the last day of the relevant period, making it impossible to predict the timing and magnitude of any future write downs. To the extent our finding and development costs increase, we will become more susceptible to ceiling test write downs in low price environments.

Failure to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business and operating results and/or result in a loss of investor confidence in our financial reports, which could in turn have a material adverse effect on our business and stock price.

        Under current SEC rules, we will be required to issue a report assessing the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act as of December 31, 2007 and on an annual basis thereafter. This assessment will require us to document, assess and test our internal controls over financial reporting more comprehensively than applicable rules currently require. In addition, our outside auditors will be required to audit and report on our assessment of our internal controls.

        To complete our assessment, we will be required to enhance the documentation of our policies, procedures and internal controls over financial reporting, assess the effectiveness of the design of those controls and test whether those controls are operating as designed. This process, which we have begun with the assistance of an independent consulting firm, will involve considerable time and expense. The operations we acquired as a result of the TexCal transaction have increased the scope and complexity of

26



the process. During the course of our assessment, we may identify material weaknesses that we cannot remediate in time to meet the deadline imposed by SEC rules for certification of our internal controls. A determination that a material weakness exists as of December 31, 2007 or a subsequent date could result in adverse publicity, regulatory scrutiny and a loss of investor confidence in the accuracy and completeness of our financial reports. If our ability to report our financial results in a timely and accurate manner were negatively affected, this could have a material adverse effect on our stock price.

        In November 2005, we restated the financial statements included in our Quarterly Reports on Form 10-Q for the first two quarters of 2005. In addition, we have historically operated with a relatively small number of employees in the accounting and financial reporting area. If we had previously conducted an assessment of our internal controls under the standards set forth in Section 404 of the Sarbanes-Oxley Act and related rules, either or both of these factors likely would have led us to conclude that we had one or more material weaknesses in our internal controls. In addition, our outside auditors, in the performance of their 2005 audit, concluded that material weaknesses in our internal controls existed in 2005. The efforts we have undertaken, or will undertake, to address these issues, or similar issues that may arise or be discovered in the future, may not be successful.

        Particularly in view of the fact that we operate with a relatively small number of employees, the loss of any of our key accounting personnel, especially David Christofferson, our Chief Financial Officer, or Douglas Griggs, our Chief Accounting Officer, would adversely impact the effectiveness of our control environment and our internal controls, including our internal control over financial reporting.

Risks Related to This Offering and to Owning Our Common Stock

There has been no prior market for our common stock. The market price for our common stock could be volatile, and the value of your investment could decline.

        Prior to this offering, there has been no public market for our common stock, and an active trading market may not develop or be sustained after this offering. The market price for our common stock will vary from the initial public offering price after trading commences, and you may not be able to resell your shares of common stock at or above the initial offering price. This could result in substantial losses for you. The initial public offering price will be determined by negotiation between us, the Marquez Trust and the underwriters based upon a number of factors and may not be indicative of future market prices for our common stock. The market price of our common stock will be significantly affected by the price of oil and natural gas and may fluctuate significantly in response to a number of other factors, some of which are beyond our control. Some of the factors that could negatively affect our stock price include:

    actual or anticipated variations in our reserve estimates and quarterly or annual operating results;

    decreases in oil and natural gas prices;

    changes in operating cash flow;

    publication of research reports about us or the oil and natural gas exploration and production industry;

    increases in market interest rates, which may increase our debt service obligations and our cost of capital;

    changes in applicable laws or regulations, court rulings and enforcement and legal actions;

    changes in market valuations of similar companies;

    adverse market reaction to our level of indebtedness;

27


    departures of key management personnel;

    actions by our stockholders, including sales of stock by the selling stockholders;

    speculation in the press or investment community; and

    general market and economic conditions.

Investors in this offering will suffer immediate and substantial dilution.

        The offering price per share of our common stock offered under this prospectus is higher than the net tangible book value per share of our common stock outstanding immediately after this offering. Our net tangible book value per share as of June 30, 2006 was approximately $0.16. Net tangible book value per share as of June 30, 2006 represents the amount of our total tangible assets minus our total liabilities, divided by the 32,692,500 shares of our common stock that were outstanding on June 30, 2006. Investors who purchase our common stock in this offering will pay a price per share that exceeds the net tangible book value per share of our common stock. If you purchase our common stock in this offering, you will experience immediate and substantial dilution of $15.57 in the net tangible book value per share of our common stock, based upon the offering price of $20.00 per share. Investors who purchase our common stock in this offering will have purchased 23% of the shares outstanding immediately after the offering, but will have paid 98% of the total consideration for those shares.

We have no plans to pay dividends on our common stock.

        We have no plans to declare or pay any dividends on our common stock. Our debt agreements restrict our ability to pay dividends on our common stock, and we may also enter into other credit agreements or other borrowing arrangements in the future that contain similar, and possibly more stringent, limitations. When we pay dividends on our common stock, we are obligated to make a bonus payment to each holder of stock options granted under our 2000 stock incentive plan in an amount equal to the dividend that would have been paid on the shares of common stock underlying the holder's options had those options been exercised as of the record date relating to the dividend. See "Management—Stock Option Plans—2000 Stock Incentive Plan."

We will be controlled by Timothy Marquez, who will be able to determine the outcome of matters submitted to a vote of our stockholders. This will limit the ability of other stockholders to influence our management and policies.

        Timothy Marquez, our Chairman and CEO, currently beneficially owns 92% of our outstanding common stock and will continue to beneficially own approximately 68% of our outstanding common stock following the offering (or 65% if the underwriters exercise in full their option to purchase additional shares). As a result, Mr. Marquez is and will be able to control the composition of our board of directors and direct our management and policies. Through this control, Mr. Marquez will have the direct or indirect power to:

    elect all of our directors and thereby control our policies and operations;

    amend our certificate of incorporation and bylaws;

    appoint our management;

    approve future issuances of our common stock or other securities,

    approve the payments of dividends, if any, on our common stock;

    approve the incurrence of debt by us; and

    agree to or prevent mergers, consolidations, sales of all or substantially all our assets or other extraordinary transactions.

28


        Mr. Marquez's significant ownership interest could adversely affect investors' perceptions of our corporate governance. In addition, Mr. Marquez may have an interest in pursuing acquisitions, divestitures and other transactions that involve risks to us and you. For example, Mr. Marquez could cause us to make acquisitions that increase our indebtedness or to sell revenue generating assets. Mr. Marquez may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Also, we have engaged, and may continue to engage, in related party transactions involving Mr. Marquez, such as our purchase of the membership interests of Marquez Energy. Of the aggregate closing payment of $16.6 million made to former members of Marquez Energy in that transaction, Mr. Marquez and David Christofferson, our CFO, received $13.0 million and $1.6 million, respectively. We may also be required to make certain contingent payments to the former holders of membership interests in Marquez Energy as described in "Management's Discussion and Analysis of Financial Conditions and Results of Operations—Acquisitions and Divestitures—Acquisition of Marquez Energy." In addition, we have entered into agreements with the Marquez Trust in connection with dividends of certain real property interests to the trust. See "Certain Relationships and Related Transactions—Real Property Dividends and Related Transactions." We have also entered into a registration rights agreement with the trust, as described in "Shares Eligible for Future Sale—Registration Rights Agreement."

Some of our directors have relationships with other companies in the oil and natural gas industry that could result in conflicts of interest.

        Some of our directors serve as directors and/or officers of other companies engaged in the oil and natural gas industry and may have other relationships with such companies. For example, Timothy Brittan is President of Infinity Oil & Gas, Inc. and Glen C. Warren is the President, CFO and a director of Antero Resources Corporation. In addition, Mac McFarland provides consulting services to various energy-related companies from time to time and Joel Reed is the lead principal of a firm that provides investment banking services to such companies from time to time. To the extent those companies are involved in ventures in which we may participate, or compete for acquisitions or financial resources with us, the relevant director will face a conflict of interest. In the event such a conflict arises, the relevant director will be required to disclose the nature and extent of the conflict and abstain from voting for or against any action of the board that is or could be affected by the conflict.

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public markets, including sales by the selling stockholders, or the issuance of additional shares of common stock in future acquisitions.

        Sales of a substantial number of shares of our common stock in the public market after this offering, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares in the public market or the possibility of such sales could impair our ability to raise capital through the sale of additional common or preferred stock. After this offering, we will have 42,692,500 shares of common stock outstanding. Of these shares, all shares sold in the offering, other than shares purchased by our affiliates, will be freely tradable (except that shares sold in the directed share program will be subject to lock-up agreements as described in "Underwriting"). Following the offering, the selling stockholders will own approximately 71% of our outstanding common stock (or 68% if the underwriters exercise in full their option to purchase additional shares). These shares are "restricted securities" within the meaning of Rule 144 under the Securities Act. In general, upon satisfaction of certain conditions, Rule 144 permits the sale of limited amounts of restricted securities one year following the date of acquisition of the restricted securities. All of the selling stockholders' shares of common stock will be deemed to satisfy the holding period requirement of Rule 144. In addition, we have entered into a registration rights agreement with the Marquez Trust pursuant to which it is entitled to require us to register for resale some or all of its

29



shares under the Securities Act, subject to certain conditions. Because of the substantial size of the trust's holdings, the sale of a significant portion of its shares, or a perception in the market that such a sale is likely, could have a significant impact on the market price of our common stock. See "Shares Eligible for Future Sale."

        Pursuant to our 2000 and 2005 stock incentive plans, we have granted options to purchase an aggregate of approximately 4.3 million shares of our common stock to certain of our directors and employees, approximately 39% of which are currently vested. Promptly following the completion of this offering, we expect to grant options to purchase up to an additional 500,000 shares of our common stock to our non-executive officer employees, 20% of which will be vested on the date of grant. Upon exercise, the shares underlying the options will be eligible for sale in the public market if they are registered under the Securities Act or qualify for an exemption from the registration requirements of the Securities Act pursuant to Rule 144, subject to the lock-up agreements described in "Underwriting." Promptly following the completion of this offering, we intend to file a Form S-8 with respect to shares purchasable upon exercise of options granted under those plans, which will facilitate their resale in the public market.

        In addition, in the future, we may issue shares of our common stock in connection with acquisitions of assets or businesses. If we use our shares for this purpose, the issuances could have a dilutive effect on the value of your shares, depending on market conditions at the time of an acquisition, the price we pay, the value of the business or assets acquired, and our success in exploiting the properties or integrating the businesses we acquire and other factors.

Our certificate of incorporation and bylaws and Delaware law contain provisions that may prevent, discourage or frustrate attempts to replace or remove our current management by our stockholders, even if such replacement or removal may be in our stockholders' best interests.

        Our certificate of incorporation and bylaws and Delaware law contain provisions that could enable our management, including Mr. Marquez, to resist a takeover attempt (even if Mr. Marquez ceases to beneficially own a controlling block of our common shares). These provisions:

    restrict various types of business combinations with significant stockholders (other than the Marquez Trust, Mr. Marquez and his wife);

    provide for a classified board of directors;

    limit the right of stockholders to remove directors or change the size of the board of directors;

    limit the right of stockholders to fill vacancies on the board of directors;

    limit the right of stockholders to act by written consent or call a special meeting of stockholders;

    require a higher percentage of stockholders than would otherwise be required to amend, alter, change or repeal certain provisions of our certificate of incorporation; and

    authorize the issuance of preferred stock with any voting rights, dividend rights, conversion privileges, redemption rights and liquidation rights and other rights, preferences, privileges, powers, qualifications, limitations or restrictions as may be specified by our board of directors.

These provisions could:

    discourage, delay or prevent a change in the control of our company or a change in our management, even if the change would be in the best interests of our stockholders;

    adversely affect the voting power of holders of common stock; and

    limit the price that investors might be willing to pay in the future for shares of our common stock.

30



USE OF PROCEEDS

        We estimate that our net proceeds from the sale of 10,000,000 shares of common stock in this offering, after deducting estimated fees and expenses and underwriting discounts, will be approximately $184.5 million, assuming an offering price of $20.00 per share, which is the midpoint of the range set forth on the cover page of this prospectus.

        We anticipate that the net proceeds will be used to repay outstanding indebtedness under the revolving credit facility and the second lien term loan facility. Initially, we will prepay $100.3 million under our revolving credit facility and offer to prepay $84.3 million under our second lien term loan facility. If some or all of the lenders under our second lien term loan facility decline our prepayment offer (as they are permitted to do under the second lien term loan agreement), we anticipate that we will apply all of the declined amount to further reduce outstanding borrowings under the revolving credit facility.

        We borrowed $350 million under the second lien term loan facility on March 30, 2006 to finance part of the purchase price for TexCal. We borrowed $119.5 million under the revolving credit facility on March 31, 2006 to finance the remainder of the purchase price for TexCal and to pay related fees and expenses. As of October 26, 2006, $538.5 million was outstanding under the credit facilities. As of that date, the interest rate on amounts borrowed under the second lien term loan was 9.93% and the interest rate on amounts borrowed under the revolving credit facility was 7.96%. The interest rate on amounts borrowed under the second lien term loan facility and the revolving credit facility will decrease by 0.5% following the completion of this offering if our net proceeds from the offering are at least $200.0 million. The second lien term loan facility matures on March 30, 2011 and the revolving credit facility matures on March 30, 2009.

        We will not receive any of the proceeds from the sale of shares of our common stock in this offering by the selling stockholders, one of which is a family trust controlled by our CEO. Affiliates of certain of the underwriters are lenders under our credit facilities and will therefore receive a portion of the net proceeds of this offering. See "Underwriting."


DIVIDEND POLICY

        We have no plans to pay dividends on our common stock. We will pay dividends on our common stock only if and when declared by our board of directors. Our board's ability to declare a dividend is subject to limits imposed by our debt agreements and Delaware law. In determining whether to declare dividends, the board will consider those limits, our financial condition, results of operations, working capital requirements, future prospects and other factors it considers relevant. When we pay dividends on our common stock, we are obligated to make a bonus payment to each holder of stock options granted under our 2000 stock incentive plan in an amount equal to the dividend that would have been paid on the shares of common stock underlying the holder's options had those options been exercised as of the record date relating to the dividend. See "Management—Stock Option Plans—2000 Stock Incentive Plan."

31



CAPITALIZATION

        The following table sets forth our capitalization as of June 30, 2006:

    on a historical basis; and

    on an as adjusted basis to give effect to the sale of 10,000,000 shares of our common stock at an assumed offering price of $20.00 per share, which is the midpoint of the range set forth on the cover page of this prospectus, after deducting estimated fees and expenses (including fees and expenses related to sales by the selling stockholders) and underwriting discounts, and the utilization of the net proceeds in the manner set forth in "Use of Proceeds." The table should be read in conjunction with our financial statements and the notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this prospectus.

 
  As of June 30, 2006
 
 
  Actual
  As Adjusted
 
 
  (in thousands,
except share data)

 
Cash and cash equivalents   $ 13,387   $ 13,387  
   
 
 
Long term debt:              
  Credit facilities(1)     509,529     325,029  
  Senior notes     149,248     149,248  
   
 
 
    Total long term debt   $ 658,777   $ 474,277  
Stockholders' equity (deficit):              
Common stock, $.01 par value (200,000,000 shares authorized, 32,692,500 shares issued and outstanding actual; 42,692,500 shares issued and outstanding as adjusted)     327     427  
Additional paid-in capital     21,761     206,161  
Retained earnings (accumulated deficit)(2)     (2,610 )   (3,390 )
Accumulated other comprehensive income (loss)     (14,191 )   (14,191 )
   
 
 
Total stockholders' equity     5,287     189,007  
   
 
 
Total long-term debt and stockholders' equity   $ 664,064   $ 663,284  
   
 
 

(1)
As of October 26, 2006, $188.5 million was outstanding under the revolving credit facility and $350 million was outstanding under the second lien term loan facility. Based on those amounts, if all lenders under the second lien term loan facility accept our prepayment offer (see "Use of Proceeds"), $88.3 million will remain outstanding under the revolving credit facility and $265.8 million will remain outstanding under the second lien term loan facility following the utilization of the net proceeds of this offering. If all of the lenders under the second lien term loan facility reject our prepayment offer and the associated proceeds are applied to further reduce borrowings under the revolving credit facility, $4.0 million will remain outstanding under that facility and $350.0 million will remain outstanding under the second lien term loan facility following the offering. See "Description of Indebtedness."

(2)
The as adjusted amount reflects costs relating to FAS 123R of $780,000, net of related taxes.

32



SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This prospectus includes forward-looking statements. All statements other than statements of historical fact included in this prospectus are forward-looking statements and are subject to risks and uncertainties. Forward-looking statements generally can be identified by the use of forward-looking terminology such as "may," "expect," "intend," "estimate," "anticipate," "believe" or "plan" or the negative thereof or variations thereon or similar terminology. Forward-looking statements relate to, among other things:

    our future financial position, including cash flow and anticipated liquidity;

    amounts and nature of future capital expenditures;

    acquisitions and other business opportunities;

    operating costs and other expenses;

    wells to be drilled or reworked;

    oil and natural gas prices and demand;

    exploitation, development and exploration prospects;

    asset retirement obligations;

    estimates of proved oil and natural gas reserves;

    reserve potential;

    development and infill drilling potential;

    expansion and other development trends in the oil and natural gas industry;

    business strategy;

    production of oil and natural gas;

    transportation of the oil and natural gas we produce;

    planned or possible asset sales or dispositions; and

    expansion and growth of our business and operations.

        Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations may prove to be incorrect. Disclosure of important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are included under "Risk Factors" and elsewhere in this prospectus, including, without limitation, in conjunction with the forward-looking statements. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

        Factors that could cause actual results to differ materially from our expectations include, among others, such things as:

    acquisitions and other business opportunities (or the lack thereof) that may be presented to and pursued by us;

    competition for available properties and the effect of such competition on the price of those properties;

33


    oil and natural gas prices;

    risks related to our level of indebtedness;

    our ability to replace oil and natural gas reserves;

    loss of senior management or technical personnel;

    risks arising out of our hedging transactions;

    our inability to access oil and natural gas markets due to operational impediments;

    uninsured or underinsured losses in our oil and natural gas operations;

    inaccuracy in reserve estimates and expected production rates;

    exploitation, development and exploration results, including from enhanced recovery activities;

    costs related to asset retirement obligations;

    a lack of available capital and financing;

    the potential unavailability of drilling rigs and other field equipment and services;

    the existence of unanticipated liabilities or problems relating to the TexCal transaction or other acquisitions;

    difficulties involved in the integration of TexCal and other operations we may acquire in the future;

    general economic, market or business conditions;

    factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment, permitting issues, weather and limits on the number of activities that can be conducted at any one time on our offshore platforms;

    the impact and costs related to compliance with or changes in laws or regulations governing our oil and natural gas operations;

    environmental liabilities;

    risk factors discussed in this prospectus; and

    other factors, many of which are beyond our control.

34



UNAUDITED PRO FORMA FINANCIAL INFORMATION

        We are providing the following unaudited pro forma condensed combined financial information to present the results of operations of the combined company giving effect to the TexCal transaction as though our business and that of TexCal had been combined at the dates indicated and for the periods shown. The pro forma adjustments made are based upon available information and assumptions that we believe are reasonable. The unaudited pro forma condensed combined financial information is presented for illustrative purposes only and is based on the estimates and assumptions set forth in the accompanying notes. The companies may have performed differently had they been combined earlier. Investors should not rely on this information as being indicative of the results that would have been achieved had the companies been combined earlier or the future results of the combined company. The unaudited pro forma condensed combined financial information should be read in conjunction with our consolidated financial statements and those of TexCal, both of which are included elsewhere in this prospectus.

        The unaudited pro forma condensed combined financial statements reflect the following:

    Our acquisition of 100% of the membership interests in TexCal for approximately $456.8 million in cash and our incurrence of related financing costs of $14.4 million;

    The incurrence of $469.5 million principal amount of indebtedness under our credit facilities and the application of net proceeds thereof to finance the acquisition of TexCal;

    The acquisition was accounted for using the purchase method of accounting;

    Potential cost savings have not been reflected as an adjustment to the historical data. Such savings, if any, would result from the consolidation of certain offices and the elimination of duplicate corporate and field-level staff and expenses.

    The unaudited pro forma condensed combined statements of operations have been prepared as if the acquisition occurred on January 1, 2005. The unaudited pro forma condensed combined statement of operations for the six-month period ended June 30, 2006 reflects pro forma information for the quarter ended March 31, 2006 and historical information for the quarter ended June 30, 2006.

35



Unaudited Pro Forma Condensed Combined Statement of Operations
For the Year Ended December 31, 2005

 
  Venoco
  TexCal
  Pro Forma
Adjustments
(Note 2)

  Pro Forma
Combined

 
 
  (in thousands, except per share amounts)

 
Revenues                          
Oil and natural gas sales   $ 191,092   $ 82,336   $   $ 273,428  
Commodity and derivative gains (losses)—realized     (22,870 )   (3,210 )       (26,080 )
Commodity and derivative gains (losses)—unrealized     (34,725 )   2,975         (31,750 )
Other     4,456     1,069         5,525  
   
 
 
 
 
    Total revenues     137,953     83,170         221,123  
Expenses                          
  Oil and natural gas production     54,038     22,201         76,239  
  Transportation expense     2,596     172         2,768  
  Depreciation, depletion and amortization     21,680     10,745     22,956   (a)   55,381  
  Accretion of abandonment liability     1,752     527         2,279  
  General and administrative, net of amounts capitalized     16,007     3,975         19,982  
  Amortization of deferred loan costs     1,755     117     2,913   (c)   4,785  
  Interest, net     13,673     828     41,944   (d)   56,445  
   
 
 
 
 
    Total expenses     111,501     38,565     67,813     217,879  
   
 
 
 
 
Income before minority interest and income taxes     26,452     44,605     (67,813 )   3,244  
Income tax provision (benefit)     10,300         (9,300 )(e)   1,000  
   
 
 
 
 
Net income before minority interest     16,152     44,605     (58,513 )   2,244  
Minority interest     42             42  
   
 
 
 
 
Net income (loss)   $ 16,110   $ 44,605   $ (58,513 ) $ 2,202  
   
 
 
 
 
Net income per share                          
  Basic   $ 0.49   $ 1.36         $ 0.07  
  Diluted   $ 0.49   $ 1.35         $ 0.07  
Weighted average shares outstanding                          
  Basic     32,693     32,693           32,693  
  Diluted     32,979     32,979           32,979  

See notes to unaudited pro forma condensed combined financial statements.

36



Unaudited Pro Forma Condensed Combined Statement of Operations
For the Six Months Ended June 30, 2006

 
  For the Three Months Ended
March 31, 2006

  Venoco
For the
Three Months
Ended
June 30,
2006

   
 
 
  Venoco
  TexCal
  Pro Forma
Adjustments
(Note 2)

  Pro Forma
Combined For the Six Months Ended June 30, 2006

 
 
  (in thousands, except per share amounts)

   
 
Revenues                                
Oil and natural gas sales   $ 51,271   $ 28,280   $   $ 76,103   $ 155,654  
Commodity and derivative gains (losses)—realized     (6,062 )   213         (6,727 )   (12,576 )
Commodity and derivative gains (losses)—unrealized     (9,508 )   57         (5,469 )   (14,920 )
Other     1,714     201         1,666     3,581  
   
 
 
 
 
 
    Total revenues     37,415     28,751         65,573     131,739  
Costs and Expenses                                
  Oil and natural gas production     12,322     6,533         23,196     42,051  
  Transportation expense     805     45         805     1,655  
  Depreciation, depletion and amortization     6,694     3,399     5,703   (a)   16,803     32,599  
  Accretion of abandonment liability     470     167         641     1,278  
  General and administrative, net of amounts capitalized     4,406     2,126     (593 )(b)   7,715     13,654  
  Amortization of deferred loan costs     338     209     728   (c)   1,133     2,408  
  Interest, net     3,773     (63 )   10,369   (d)   14,856     28,935  
   
 
 
 
 
 
    Total expenses     28,808     12,416     16,207     65,149     122,580  
   
 
 
 
 
 
Income before income taxes     8,607     16,335     (16,207 )   424     9,159  
Income tax provision (benefit)     3,500         50   (e)   100     3,650  
   
 
 
 
 
 
Net income (loss)   $ 5,107   $ 16,335   $ (16,257 ) $ 324   $ 5,509  
   
 
 
 
 
 
Net income per share                                
  Basic   $ 0.16   $ 0.50         $ 0.01   $ 0.17  
  Diluted   $ 0.15   $ 0.48         $ 0.01   $ 0.16  
Weighted average shares outstanding                                
  Basic     32,693     32,693           32,693     32,693  
  Diluted     33,862     33,862           34,170     34,022  

See notes to unaudited pro forma condensed combined financial statements.

37



Notes to Unaudited Pro Forma Condensed Combined Financial Statements

1.     Basis of Presentation

        The accompanying unaudited pro forma statements of operations present the pro forma effects of the acquisition. The statements of operations are presented as though the acquisition had occurred on January 1, 2005. Venoco and TexCal both use the full cost method of accounting for their oil and natural gas producing activities. Venoco accounted for the acquisition using the purchase method of accounting. The purchase price was allocated to TexCal's assets and liabilities, based on their estimated fair values as of the date of the acquisition. The purchase method of accounting requires that the TexCal assets acquired and liabilities assumed by Venoco be recorded at their estimated fair values. In addition, deferred income taxes are recognized for the differences between the revised carrying amounts of TexCal's assets and liabilities and their associated tax bases.

        The calculation of the total purchase price and the preliminary allocation of this price to assets and liabilities are shown below.

 
  (in thousands)
 
Calculation of purchase price:        
  Costs paid by Venoco   $ 455,879  
  Plus: Estimated acquisition costs to be incurred     931  
   
 
    Total purchase price   $ 456,810  
   
 
Allocation of purchase price:        
  Current assets   $ 25,834  
  Oil and gas properties     458,946  
  Other property and equipment     786  
  Other non-current assets     1,018  
  Current liabilities     (22,052 )
  Long-term asset retirement obligation     (7,722 )
   
 
    Net assets   $ 456,810  
   
 

        The purchase price allocation is preliminary and is subject to change for actual acquisition costs incurred. These changes will impact future depletion expense. For purposes of these pro forma financial statements, fair values were assessed as of the date of the acquisition and, accordingly, subsequent adjustments in historical amounts will be included in the amount allocated to oil and natural gas properties.

2.     Pro Forma Adjustments Related to the Acquisition

        The unaudited pro forma statements of operations include the following adjustments:

    (a)
    This adjustment increases TexCal's historical depreciation, depletion, and amortization expense associated with oil and natural gas properties based on the pro forma allocation of purchase price to oil and natural gas properties.

    (b)
    This adjustment decreases TexCal's general and administrative expenses for legal fees related to the TexCal transaction.

    (c)
    This adjustment increases Venoco's expense for amortization of deferred loan costs for costs incurred related to the amended revolving credit facility and the second lien term loan facility entered into in connection with the acquisition.

38


    (d)
    This adjustment increases Venoco's interest expense related to the $469.5 million in additional debt incurred under the amended revolving credit facility and the second lien term loan facility to finance the acquisition.

    (e)
    This adjustment records the income tax impact of TexCal's results of operations and the depreciation, depletion and amortization expense, the amortization of deferred loan costs and the interest expense pro forma adjustments at an estimated effective income tax rate of 40.0%.

3.     Supplemental Pro Forma Information Related to Oil and Natural Gas Producing Activities

        The following pro forma supplemental information relating to oil and natural gas operations is presented pursuant to Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities. The oil and natural gas producing activities are conducted onshore within the continental United States and offshore in federal and state waters off the coast of California. The evaluations of the oil and natural gas reserves at December 31, 2005 were estimated by independent petroleum engineering firms.

Pro Forma Estimated Net Quantities of Natural Gas and Oil Reserves

        The following tables set forth the net proved reserves, including changes, and proved developed reserves (all within the United States) for Venoco, TexCal and the combined company on a pro forma basis for the year ended December 31, 2005.


Crude Oil, Liquids, and Condensate (MBbls)

 
  Venoco
  TexCal
  Pro Forma
Combined

 
Proved reserves as of December 31, 2004   39,935   14,148   54,083  
  Revisions of previous estimates   (318 ) 1,235   917  
  Extensions, discoveries and improved recovery   1,580   379   1,959  
  Purchases of reserves in place   2     2  
  Production   (2,953 ) (775 ) (3,728 )
  Sales of reserves in place   (2,946 ) (313 ) (3,259 )
   
 
 
 
Proved reserves as of December 31, 2005   35,300   14,674   49,974  
   
 
 
 
Proved developed reserves as of:              
  December 31, 2004   28,035   12,653   40,688  
  December 31, 2005   24,154   12,819   36,973  

39



Natural Gas (MMcf)

 
  Venoco
  TexCal
  Pro Forma
Combined

 
Proved reserves as of December 31, 2004   69,876   80,513   150,389  
  Revisions of previous estimates   (6,083 ) (2,369 ) (8,452 )
  Extensions, discoveries and other additions   7,240   26,812   34,052  
  Purchases of reserves in place   13,390     13,390  
  Production   (7,588 ) (4,854 ) (12,442 )
  Sales of reserves in place   (2,782 )   (2,782 )
   
 
 
 
Proved reserves as of December 31, 2005   74,053   100,102   174,155  
   
 
 
 
Proved developed reserves as of:              
  December 31, 2004   49,418   18,757   68,175  
  December 31, 2005   53,390   28,557   81,947  

Pro Forma Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

        The following tables set forth the standardized measure of discounted future net cash flows associated with proved oil and natural gas reserves for Venoco, TexCal and the combined company on a pro forma basis as of December 31, 2005 and for the year then ended.

 
  Venoco
  TexCal
  Pro Forma
Combined

 
 
  (in thousands)

 
Future cash inflows   $ 2,456,617   $ 1,684,326   $ 4,140,943  
Future costs:                    
  Production     (876,858 )   (509,798 )   (1,386,656 )
  Development     (163,476 )   (93,302 )   (256,778 )
  Income taxes     (516,416 )   (355,107 )   (871,523 )
   
 
 
 
Future net cash flows     899,867     726,119     1,625,986  
10% annual discount for estimated timing of cash flows     (334,482 )   (351,555 )   (686,037 )
   
 
 
 
Standardized measure of discounted future net cash flows at December 31, 2005   $ 565,385   $ 374,564   $ 939,949  
   
 
 
 

40



SELECTED FINANCIAL DATA

        The following table presents selected historical financial information for the periods indicated. The historical financial information for each of the years in the five-year period ended December 31, 2005 was derived from our audited financial statements and the historical financial information for the six-month periods ended June 30, 2005 and 2006 was derived from our unaudited interim financial statements. The audited financial statements for each of the years in the three-year period ended December 31, 2005 and the unaudited financial information for the six-month periods ended June 30, 2005 and 2006 are included elsewhere in this prospectus. In the opinion of management, our unaudited interim financial statements reflect all adjustments necessary to present fairly our financial position at June 30, 2005 and 2006 and our income and cash flows for the six-month periods ended June 30, 2005 and 2006. All such adjustments are of a normal recurring nature.

        The historical financial information set forth below is not necessarily indicative of future results. We urge you to read the selected financial information set forth below in conjunction with the audited financial statements included in this prospectus and the information contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this prospectus.

 
  Year ended December 31,
  Six Months ended June 30,
 
 
  2001
  2002
  2003
  2004(5)(6)
  2005
  2005
  2006
 
 
  (Predecessor)

  (Predecessor)

  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
 
  (in thousands)

 
Statement of Operations Data:                                            
  Oil and natural gas revenues   $ 135,459   $ 93,475   $ 109,754   $ 139,961   $ 191,092   $ 87,390   $ 127,374  
  Commodity derivative losses—realized     (4,493 )   (7,618 )   (10,272 )   (17,589 )   (22,870 )   (7,155 )   (12,789 )
  Commodity derivative losses—unrealized     1,550     (2,953 )       (1,096 )   (34,725 )   (27,999 )   (14,977 )
  Other revenues(1)     6,185     2,580     5,253     5,457     4,456     2,091     3,380  
   
 
 
 
 
 
 
 
    Total revenues     138,701     85,484     104,735     126,733     137,953     54,327     102,988  
  Production expenses     53,195     43,337     45,617     49,567     54,038     24,282     35,518  
  Transportation expense     2,353     2,216     2,785     2,915     2,596     1,216     1,610  
  Depreciation, depletion and amortization     18,271     19,630     16,161     16,489     21,680     9,493     23,497  
  Accretion of abandonment liability             1,401     1,482     1,752     1,018     1,111  
  General and administrative expenses, net of capitalized amounts     12,173     16,018     11,632     11,272     16,007     7,699     12,121  
  Litigation settlement expense(2)             6,000                  
  Amortization of deferred loan costs     604     464     370     3,050     1,755     1,021     1,471  
  Interest expense, net     3,676     2,343     2,125     2,269     13,673     6,820     18,629  
  Income taxes     17,425     500     7,876     16,088     10,300     774     3,600  
  Minority interest in Marquez Energy                 95     42     42      
  Cumulative effect of change in accounting principle, net of tax(3)             (411 )                
   
 
 
 
 
 
 
 
  Net income     31,004     976     11,179     23,506     16,110     1,962     5,431  
  Preferred stock dividends     (7,249 )   (8,465 )   (8,465 )   (7,134 )            
  Excess of carrying value over repurchase price of preferred stock(4)                 29,904              
   
 
 
 
 
 
 
 
  Net income (loss) applicable to common equity   $ 23,755   $ (7,489 ) $ 2,714   $ 46,276   $ 16,110   $ 1,962   $ 5,431  
   
 
 
 
 
 
 
 
Basic earnings (loss) per common share:                                            
  Income (loss) before cumulative effect of change in accounting principle   $ 0.68   $ (0.21 ) $ 0.07   $ 1.33   $ 0.49   $ 0.06   $ 0.17  
Cumulative effect of change in accounting principle             0.01                  
   
 
 
 
 
 
 
 
  Total   $ 0.68   $ (0.21 ) $ 0.08   $ 1.33   $ 0.49   $ 0.06   $ 0.17  
   
 
 
 
 
 
 
 
                                             

41


Diluted earnings (loss) per common share:                                            
  Income (loss) before cumulative effect of change in accounting principle   $ 0.61   $ (0.21 ) $ 0.07   $ 0.48   $ 0.49   $ 0.06   $ 0.16  
Cumulative effect of change in accounting principle             0.01                  
   
 
 
 
 
 
 
 
  Total   $ 0.61   $ (0.21 ) $ 0.08   $ 0.48   $ 0.49   $ 0.06   $ 0.16  
   
 
 
 
 
 
 
 
Cash Flow Data:                                            
  Cash provided (used) by                                            
    Operating activities   $ 50,417   $ 30,284   $ 31,557   $ 43,309   $ 39,931   $ 28,221   $ 60,370  
    Investing activities     (34,199 )   (38,916 )   (10,531 )   (27,990 )   (58,695 )   (46,047 )   (531,262 )
    Financing activities     (16,226 )   14,484     (23,333 )   30,979     (26,562 )   (31,228 )   474,890  
Other Financial Data (unaudited):                                            
  Adjusted EBITDA(7)   $ 69,430   $ 26,866   $ 38,122   $ 62,498   $ 98,243   $ 48,069   $ 68,914  
  Capital expenditures     42,205     38,843     9,064     21,829     90,106     32,809     86,774  
 
  Year ended December 31,
   
 
  June 30,
2006

 
  2001
  2002
  2003
  2004(5)
  2005
 
  (Predecessor)

  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
  (in thousands)

Balance Sheet Data (end of period):                                    
  Cash and cash equivalents   $ 4,746   $ 10,724   $ 8,417   $ 54,715   $ 9,389   $ 13,387
  Plant, property and equipment, net     140,046     159,257     170,663     198,563 (7)   233,776     743,223
  Total assets     177,074     206,101     212,252     298,882 (7)   302,558     853,299
  Long-term debt, excluding current portion     53,000     46,302     22,969     163,542     178,943     658,777
  Mandatorily redeemable preferred stock and accrued dividends     79,888     86,305     94,770              
  Stockholders' equity (deficit)     11,075     (641 )   2,484     48,439 (6)   4,334     5,287

(1)
Other revenues primarily include amounts received from purchasers of our oil production to reimburse us for transportation and barge expenses. In 2001, other revenues include a gain of $1.7 million on the sale of a building.

(2)
Amount comprises settlement costs incurred by us in connection with a lawsuit brought by Mr. Marquez asserting wrongful termination and breach of contract. See "Certain Relationships and Related Transactions—Ownership and Related Disputes and Transactions—Filing of Marquez Actions."

(3)
The amount shown for 2003 is the cumulative effect of change in accounting principle of $411,000, net of tax. On January 1, 2003, we adopted SFAS 143, "Accounting for Asset Retirement Obligations," which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Pursuant to our adoption of SFAS 143, we recognized a credit during the first quarter of 2003 of $411,000, net of tax, for the cumulative effect of the change in accounting principle. See note 13 to our financial statements.

(4)
Amount comprises the excess of the carrying value over the repurchase price of the mandatorily redeemable convertible preferred stock plus accrued and unpaid dividends net of unamortized issuance costs.

(5)
Marquez Energy is included in our statements of operations, balance sheet and cash flow data from July 2004, when common control between our company and Marquez Energy was established. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Accounting Matters—Acquisition of Marquez Energy."

(6)
Mr. Marquez's percentage beneficial ownership in our common stock increased from approximately 94% to 100% on December 22, 2004, the date we effected a merger with a corporation the sole stockholder of which was the Marquez Trust. Accordingly, Mr. Marquez's basis in our assets has been "pushed-down" as of the date of the merger, meaning that our post-transaction financial statements reflect Mr. Marquez's basis in our assets (the successor basis) rather than our historical basis. The aggregate purchase price has been allocated to a portion of the underlying assets and liabilities based upon their respective fair values at the date of the merger, with the values of certain long-lived assets reduced on a pro rata basis for the excess of Mr. Marquez's portion of the fair value of acquired net assets over the purchase price of the shares acquired. Due to the de minimis impact on our results of operations for the nine-day period ended December 31, 2004, the successor basis of accounting has been applied to our financial statements as of December 31, 2004, with the consolidated statements of operations, comprehensive income (loss), and cash flows for the fiscal year ended 2004 being presented on a historical, or "predecessor" basis. See note 1 to our financial statements.

(7)
We set forth our definition of Adjusted EBITDA and a reconciliation of net income to Adjusted EBITDA on pages 12-13.

42



MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

        The following discussion and analysis should be read in conjunction with our financial statements and related notes and the other information appearing elsewhere in this prospectus.

Overview

        We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Since the change in our senior management that occurred in June 2004, we have returned to our historical strategy of devoting substantial resources to exploration, exploitation and development projects on our properties. Pursuit of this strategy has led to increases in our oil and natural gas production. Our average net production for the second quarter of 2006 was 17,114 BOE/d, compared to 11,215 BOE/d for the first quarter of 2006 and 11,555 BOE/d for 2005 as a whole. Our second quarter 2006 results include the effect of the TexCal transaction. We expect our production to continue to increase in both the third and fourth quarters of 2006 relative to the same periods in 2005, and to increase quarter to quarter throughout 2007. See "—Trends Affecting Our Results of Operations." Because of the anticipated increases in production and the effect of our hedging program, we expect revenues, not including the effect of non-cash, unrealized derivative gains and losses, to increase in 2006 compared to 2005, and 2007 compared to 2006, even if oil and natural gas prices decline moderately. Our proved reserves as of July 31, 2006 were 94.5 MMBOE, representing a 20% increase from our pro forma proved reserves of 79.0 MMBOE as of December 31, 2005. We believe that pursuit of our business strategy will allow us to continue to increase our proved reserves (excluding the effect of future changes in commodity prices).

        In the execution of our business strategy, our management is principally focused on increasing our reserves of oil and natural gas and on continuing and strengthening the trend of increasing production through exploration, exploitation and development activities, acquisitions and the resolution of operational problems as they arise. Our management is also focused on the risks and opportunities associated with current oil and natural gas prices, which are generally high compared to historical averages, and on the goal of maximizing production rates while operating in a safe manner. For further information on our business strategy, the opportunities we intend to pursue and the risks and uncertainties to which our business is subject, see "Summary—Our Strategy" and "Risk Factors."

        Rising oil and natural gas prices created substantial unrealized commodity derivative losses in 2005 and rising oil prices led to further unrealized commodity derivative losses in the first half of 2006. These unrealized losses, which totaled $34.7 million in 2005 and $15 million in the first half of 2006, resulted from mark-to-market valuations for non-highly effective or ineffective portions of our derivative positions and are reflected as commodity derivative losses in our income statement. Any payments actually due to counterparties in the future on these derivatives will ultimately be funded by higher prices received from the sale of our production. We have also experienced realized commodity derivative losses, including $12.8 million in such losses in the first half of 2006. Recent increases in derivative swap and collar prices would result in these losses being substantially reduced in 2007 if current commodity prices remain stable. Our disciplined hedging strategy, which includes the use of collars, swaps and purchased floors, has allowed us to lock in minimum future floor prices we consider attractive on substantial production volumes through December 2010, while often allowing upside participation. See "—Qualitative and Quantitative Disclosures About Market Risk."

Capital Expenditures

        We have developed an active capital expenditure program to take advantage of our inventory of drilling prospects. Our exploration, exploitation and development capital expenditures of $83.6 million

43



in 2005 were more than three times our 2004 capital expenditures of $23.2 million. We drilled 17 new onshore wells to total depth in 2005 and recompleted 35 additional onshore wells. Offshore, we drilled four wells to total depth and recompleted three. Our overall capital expenditures in 2005 consisted of $32.9 million for drilling and rework activities, $28.6 million for facilities and $22.1 million for exploration projects. In addition, we spent $10.4 million on acquisitions of oil and natural gas properties in 2005, not including the acquisition of Marquez Energy or the Union Island pipeline (see "—Acquisitions and Divestitures—Other").

        We estimate that our exploration, exploitation and development capital expenditures will be approximately $185 million in 2006, including over $30 million on projects acquired as part of the TexCal transaction. In the first half of 2006, we incurred $83.5 million of capital expenditures on our projects, not including accrued capital expenditures of $2.0 million or expenditures made by TexCal prior to closing of the TexCal transaction.

        Projects we expect to pursue in 2006 in the Coastal California region include over 20 redrills, recompletions and workovers in the Sockeye and South Ellwood fields. In the first six months of 2006, we completed six workovers in the South Ellwood field and were unsuccessful with a seventh workover. We also completed three workovers in the Sockeye field. We drilled two wells in the Sockeye field, both of which were completed. We also finished testing two exploratory wells drilled in the South Ellwood field. One, the North Flank well, was dry and will be converted into a water injection well in the future. The other, the Sespe well, has been completed and is producing. We expect to increase water injection capabilities at these fields and to incorporate system upgrades to mitigate operating risks and enhance reliability.

        In the Sacramento Basin, we plan to drill approximately 80 new wells and to complete approximately 50 to 75 workovers and recompletions in 2006. In the first six months of the year, we drilled and completed 23 new wells and completed 37 workovers and recompletions in the basin. We also drilled three dry wells in the basin in the first half of the year.

        In Texas, we plan to drill approximately seven new wells in 2006 and to conduct operations to increase operating efficiency and production rates in some of the fields acquired as part of the TexCal transaction. In the second quarter of 2006, subsequent to our acquisition of TexCal, we completed 32 rework operations in Texas, 28 of which were in the Hastings field, and we successfully drilled one well in the Word field.

        Exploration activities pursued in 2006 include the drilling of approximately seven exploration wells. Two of these wells were the above-described North Flank and Sespe wells drilled in the South Ellwood field. We also expect to continue our active leasing program in key areas in 2006. Although our 2007 budget has not yet been finalized, our preliminary expectations are that it will provide for slightly in excess of $200 million in exploration, exploitation and development capital expenditures. The aggregate levels of capital expenditures for 2006 and 2007, and the allocation of such expenditures, are dependent on a variety of factors, including the availability of service contractors and equipment, permitting issues, weather and limits on the number of activities that can be conducted at any one time on our offshore platforms. Accordingly, the actual levels of capital expenditures and the allocation of such expenditures may vary materially from the above estimates.

Acquisitions and Divestitures

        TexCal Transaction.    We acquired TexCal on March 31, 2006 for $456 million in cash. According to a reserve report prepared by DeGolyer & MacNaughton, as of December 31, 2005, TexCal had proved reserves of 31.4 MMBOE. The acquisition is consistent with our strategy of acquiring large, mature fields with established reserves and significant exploitation and development potential, and provides us with substantial additions to our existing multi-year drilling inventory. TexCal acquired all of its properties in October 2004 from Tri-Union Development Corporation, or Tri-Union, which was then a

44


debtor in proceedings under Chapter 11 of the U.S. bankruptcy code. In part due to the circumstances leading to the Tri-Union bankruptcy, capital expenditures devoted to the properties were limited in the years preceding the TexCal transaction.

        The acquisition was completed pursuant to a merger agreement entered into on March 30, 2006. As contemplated by the agreement, TexCal merged with one of our wholly owned subsidiaries, with TexCal continuing as the surviving entity. TexCal made customary representations in the merger agreement regarding its business, operations and other matters, all of which expired at the closing of the transaction.

        In order to finance the $456 million purchase price for the acquisition and related transaction costs of approximately $14.4 million, we borrowed approximately $119.5 million under the revolving credit facility and $350 million under the second lien term loan facility. We intend to use the net proceeds we receive in this offering to reduce the outstanding indebtedness under these facilities. See "Use of Proceeds." The revolving credit facility has an aggregate maximum loan amount of $300 million and a current borrowing base of $230 million.

        Acquisition of Marquez Energy.    We completed our acquisition of Marquez Energy, a Colorado limited liability company majority owned and controlled by our CEO, Timothy Marquez, on March 21, 2005. According to a reserve report prepared by NSAI, Marquez Energy had proved reserves of approximately 2.0 MMBOE as of December 31, 2004. The purchase price for the membership interests in Marquez Energy was $16.8 million (including a $2.0 million deposit paid in 2004). The purchase price was based on the members' equity on Marquez Energy's unaudited December 31, 2004 balance sheet as adjusted to reflect the value of its oil and natural gas properties (as determined by NSAI as of December 31, 2004) and certain other adjustments. For the purpose of calculating the purchase price, the following values were assigned to Marquez Energy's proved reserves: (i) $1.75/Mcfe for its proved developed producing reserves, (ii) $1.00/Mcfe for its proved developed non-producing reserves and (iii) $0.75/Mcfe for its proved undeveloped reserves. Pursuant to the purchase agreement, NSAI conducted a supplemental evaluation of the Marquez Energy properties as of year-end 2005, and NSAI or another nationally recognized engineering firm will conduct a further evaluation as of year-end 2006. In the event the year-end 2006 evaluation attributes proved reserves to the Marquez Energy properties as of December 31, 2004 in excess of those reflected in NSAI's initial report, an additional payment will be made to the former holders of interests in Marquez Energy pursuant to the same formula, subject to a maximum aggregate price of $25.0 million, including assumption of debt. No additional payments were due as a result of the evaluation conducted by NSAI as of December 31, 2005.

        Because Marquez Energy was a company under common control with us since July 12, 2004, our financial statements and production information for all of 2005 and for the third and fourth quarters of 2004 include Marquez Energy. For the same reason, the acquisition was accounted for in a manner similar to a pooling of interests whereby the historical results of Marquez Energy have been combined with our financial results since July 1, 2004.

        Sale of Big Mineral Creek.    On March 31, 2005, we completed the sale of our Big Mineral Creek field, located in Grayson County, Texas, to BlackWell Energy Group, LLC for $44.6 million. The transaction was given economic effect as of February 1, 2005. As of December 31, 2004, the field had proved reserves of approximately 3.4 MMBOE, according to a report by NSAI. Average net production at the field was approximately 547 BOE/d in the first quarter of 2005. Pursuant to Section 1031 of the Internal Revenue Code, we effected a like-kind exchange of a portion of the Big Mineral Creek field representing approximately $15.0 million of the total sale price for certain Marquez Energy properties and properties acquired from third parties. The like-kind exchange provisions resulted in the deferral of a portion of income taxes related to the gain on sale. We did not recognize a gain on sale for financial reporting purposes, but applied the net sales proceeds to reduce the capitalized costs of our oil and natural gas properties in accordance with our full-cost accounting method.

45



        Other.    In September 2005, we acquired a 100% working interest in the Willows-Beehive Bend gas field, a 100% working interest in the Bounde Creek gas field and a 65% working interest in the Arbuckle field for an aggregate price of $10.1 million, net of certain participation rights held by third parties. We operate all of the acquired fields, which are located in the Sacramento Basin. In January 2006, we sold 35% of the interests we acquired in the Willows-Beehive Bend and Bounde Creek fields for $3.0 million. In the fourth quarter of 2005, we purchased the Union Island pipeline, a 32-mile natural gas pipeline that runs from the Union Island field to a location near Pittsburg, California, for $6.1 million. We believe that ownership of the pipeline will provide us greater marketing flexibility and will allow us to maximize the value of our natural gas production from the Union Island field. We also believe that we will benefit from third party transactions involving the pipeline.

Trends Affecting our Results of Operations

        TexCal.    Our results of operations reflect the inclusion of the TexCal properties beginning April 1, 2006. The TexCal transaction has led to significant increases in production, revenue and related expenses.

        Revenues.    Oil prices have increased significantly since the beginning of 2004, and natural gas prices, despite recent downward trends, have been substantially higher in both 2005 and 2006 than in 2004. These price increases have contributed to an increase in our oil and natural gas revenues in both 2006 compared to 2005 and 2005 compared to 2004. Price increases in 2005, together with an increase in production volumes, resulted in a 37% increase in our oil and natural gas revenues compared to 2004, although because of unrealized commodity derivative losses, our total revenues increased only 9%. In the first six months of 2006, price and production volume increases resulted in a 46% increase in oil and natural gas revenues compared to the same period in 2005, and a 90% increase in total revenues.

        Production Trends.    Our production of oil and natural gas has increased since the change in our senior management that occurred in June 2004. The management in place between mid-2002 and mid-2004 reduced capital expenditures, in part in their discretion and in part because, commencing in February 2003, a large portion of our cash flow from operations was needed to amortize the credit facility then in place, which had become a term loan. As our oil properties generally have shallow decline rates, our oil production did not decline significantly during the period despite limited capital expenditures. We averaged oil production of 8.8 MBbl/d in 2002, 8.5 MBbl/d in 2003 and 8.5 MBbl/d in 2004. Our natural gas production declines at a higher rate when exploitation and development activities are curtailed. As a result, average natural gas production decreased from 19,655 Mcf/d in 2002 to 15,362 Mcf/d in 2003 and 14,660 Mcf/d in 2004 (excluding production from Marquez Energy). As noted above (see "—Overview"), our renewed focus on acquisition, exploration, exploitation and development projects has reversed these declines, with average net production rising from 11,125 BOE/d in 2004 to 11,555 BOE/d in 2005 and to 17,114 BOE/d in the second quarter of 2006. The increase in average net production in the second quarter of 2006, from 11,215 BOE/d in the first quarter of 2006, resulted primarily from the TexCal transaction. Properties we acquired from TexCal contributed average net production of 5,645 BOE/d in the second quarter of 2006.

        Our production increased in several of our producing areas in the third quarter of 2006 relative to the previous quarter, in particular the Sacramento Basin and the Hastings field in Texas. However, we expect that overall average net production for the quarter will be approximately 16,950 BOE/d, down from 17,114 BOE/d in the second quarter of 2006, primarily as a result of two maintenance projects. First, production from the South Ellwood field was shut in for part of August due to maintenance on the barge that delivers oil from the field. As a result, we accelerated our scheduled maintenance in the field from September to August to coincide with the barge maintenance. Second, the primary pipeline serving our Willows gas field in the Sacramento Basin operated on reduced capacity for several weeks in the third quarter due to maintenance. Oil production from the South Ellwood field recommenced at

46



the end of August and natural gas production from the Willows field recommenced in September. The effect of the barge and pipeline maintenance projects was to suppress our average net production in the third quarter by approximately 1,500 BOE/d. Additionally, as described in "Business and Properties—Description of Properties—Coastal California—South Ellwood Field," the owner of the refinery to which we have historically delivered production from the South Ellwood field informed us in August 2006 that it was unwilling to accept further deliveries from the barge that services the field. As a result, we have sold recent shipments of oil production from the field to a refinery in the San Francisco area. To date, the situation has not adversely affected our production from the field, though it has resulted in reduced sales prices for the production and increased transportation costs. We are evaluating potential alternative short-term and long-term arrangements for the delivery and sale of oil production from the field, but any such arrangement may require time to implement and may require us to accept lower prices for our production and/or incur higher transportation costs. Further, we will be required to shut in the field if we are unable, for any sustained period (the length of which will vary based on the availability of storage), to implement an acceptable delivery or sales arrangement. Average net production of oil from the field was 3,374 Bbl/d in June 2006. See "Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry—The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not control. For our largest field, we rely on one barge, which is currently out of service, to transport production from the field. When these facilities or systems, including the barge, become unavailable, our operations can be interrupted and our revenues reduced."

        Expected Fourth Quarter 2006 and 2007 Production Trends.    In the fourth quarter of 2006 and in 2007, we expect that implementation of our capital expenditure program will result in production increases. We expect that we will maintain production from the majority of our properties at rates substantially consistent with third quarter 2006 levels, and that we will focus on growing production in the Sacramento Basin and the Hastings complex. We are pursuing a multi-year drilling program in the Sacramento Basin, and plan to have at least five rigs operating in the basin by early 2007. Our average net production in the basin in June 2006 was 32,438 Mcf/d from 283 gross wells, and based on anticipated rig availability, we plan to have over 400 wells operating in the basin by the end of 2007. In the Hastings complex, we are actively re-completing wells, and currently have four workover rigs in the field. We expect to continue our recompletion program in the field into 2007. Our expectations with respect to future production rates are subject to a number of uncertainties, including those associated with the availability and cost of drilling rigs and third party services, oil and natural gas prices, the potential for mechanical problems, permitting issues, drilling success rates, the availability of acceptable delivery and sales arrangements with respect to oil production from the South Ellwood field, pipeline capacity, the accuracy of our assumptions regarding the sustainability of historical growth rates, weather and those referenced in "Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry."

        Production Expenses.    Production expenses in the first half of 2006 increased to $13.84 per BOE from $11.01 in the first half of 2005. The increase was primarily attributable to substantial remedial work we conducted in the Hastings field in the second quarter of 2006. This work, together with various capital expenditures on the field, contributed to an increase in average net production from the field of approximately 360 BOE/d between March and July 2006. We expect to complete most of the remedial work in 2006 and 2007. We are adding production from our lower operating cost gas wells in the Sacramento Basin. This added production, combined with the completion of much of the remedial work in the Hastings field, is expected to result in our 2007 production expenses trending downward towards historical levels on a per BOE basis. Our expectations with respect to future per-unit expenses are based in part on the projected increases in our production described in the preceding paragraph and are subject to risks and uncertainties, including those described and referenced therein.

47



        Depletion, Depreciation and Amortization.    Our depletion, depreciation and amortization, or DD&A, rate increased in the first half of 2006 to $9.15 per BOE from $4.31 per BOE in the first half of 2005. This is due primarily to the costs of the TexCal transaction being added to our property cost basis at March 31, 2006. The second quarter 2006 DD&A rate of $10.79 per BOE is therefore more indicative of future rates than the first half 2006 rates.

        General and Administrative Expenses.    In order to manage and maximize our growth, we have been increasing our professional staff, and this has resulted in increased general and administrative costs. The TexCal transaction has also increased those costs. In the second quarter of 2006, we incurred substantial costs in connection with the integration of TexCal and various systems conversion costs. These general and administrative costs increased from $3.49 per BOE in the first half of 2005 to $4.72 per BOE in the first half of 2006. Additional integration and systems conversion costs will be incurred in the third and fourth quarters of 2006, with these projects expected to be substantially complete by year-end. We expect general and administrative costs, excluding costs relating to FAS 123R, to be less than historical costs per BOE once the integration and systems conversion projects are completed in 2006. In 2007, we expect that our per unit general and administrative costs, excluding costs relating to FAS 123R and capitalized general and administrative costs, will be roughly consistent with pre-2006 levels (assuming growth in average net production for the year as described above). However, we have not to date fully quantified the costs we expect to incur with respect to Sarbanes-Oxley Act compliance, and those costs may be significant.

        Debt Service Obligations.    The indebtedness we incurred in the TexCal transaction significantly increased our debt service obligations. Satisfaction of those obligations will require a substantial portion of the operating cash flow generated from the properties we acquired in the transaction. We intend to reduce amounts outstanding under the credit facilities with the net proceeds of this offering and thereby reduce our debt service obligations. See "—Liquidity and Capital Resources—Capital Resources and Requirements."

Internal Control Over Financial Reporting

        In November 2005, we restated the financial statements included in our Quarterly Reports on Form 10-Q for the first two quarters of 2005. In addition, we have historically operated with a relatively small number of employees in the accounting and financial reporting area. If we had previously conducted an assessment of our internal controls under the standards set forth in Section 404 of the Sarbanes-Oxley Act and related rules, either or both of these factors likely would have led us to conclude that we had one or more material weaknesses in our internal controls. In addition, our outside auditors, in the performance of their 2005 audit, concluded that material weaknesses in our internal controls existed in 2005. We are addressing these issues by adopting more extensive accounting controls and financial review procedures and have hired a Chief Accounting Officer to oversee our financial reporting processes. We have also retained an independent consulting firm with experience in the area of Sarbanes-Oxley Act compliance to assist us in documenting our policies, procedures and internal control over financial reporting, assessing the effectiveness of the design of those controls and testing whether those controls are operating as designed. In the course of this process, we have hired additional accounting staff and expect to hire additional accounting staff and take other measures to further enhance our internal controls. We will also continue to engage additional outside advisors as appropriate.

48



Results of Operations

        The following table reflects the components of our oil and natural gas production and sales prices and sets forth our operating revenues, costs and expenses on a BOE basis for the three years ended December 31, 2005 and for the six-month periods ended June 30, 2005 and 2006.

 
   
   
   
  Six Months ended June 30,
  Pro Forma
Six Months
ended
June 30,
2006

 
 
  Year ended December 31,
 
 
  2003
  2004(1)
  2005(1)
  2005(1)
  2006(2)
 
Production Volume                                      
  Natural gas (MMcf)     5,607     5,826     7,588     3,732     5,764     7,570  
  Oil (MBbls)     3,114     3,101     2,953     1,583     1,606     1,797  
  MBOE     4,049     4,072     4,218     2,205     2,567     3,059  
Daily Average Production Volume                                      
  Natural gas (Mcf/d)     15,362     15,918     20,789     20,618     42,032     41,823  
  Oil (Bbls/d)     8,532     8,472     8,090     8,745     9,982     9,928  
  BOE/d     11,092     11,125     11,555     12,181     16,987     16,899  
Oil Price per Bbl Produced (in dollars)                                      
  Realized price before commodity derivative loss   $ 26.29   $ 34.69   $ 45.66   $ 40.45   $ 57.31   $ 57.79  
  Realized commodity derivative loss     (2.39 )   (5.47 )   (7.46 )   (4.28 )   (8.83 )   (7.77 )
   
 
 
 
 
 
 
  Net realized   $ 23.90   $ 29.22   $ 38.20   $ 36.17   $ 48.48   $ 50.02  
   
 
 
 
 
 
 
Natural Gas Price per Mcf Produced (in dollars)                                      
  Realized price before commodity derivative gain (loss)   $ 5.06   $ 5.77   $ 7.45   $ 6.22   $ 6.36   $ 7.01  
  Realized commodity derivative gain (loss)     (0.50 )   (0.11 )   (0.11 )   (0.10 )   0.24     0.18  
   
 
 
 
 
 
 
  Net realized   $ 4.56   $ 5.66   $ 7.34   $ 6.12   $ 6.60   $ 7.19  
   
 
 
 
 
 
 
Average Sale Price per BOE(3)   $ 24.69   $ 30.42   $ 39.55   $ 35.87   $ 44.15   $ 46.33  
Expense per BOE                                      
  Production expenses(4)   $ 11.27   $ 12.17   $ 12.81   $ 11.01   $ 13.84   $ 13.75  
  Transportation expenses   $ 0.69   $ 0.72   $ 0.62   $ 0.55   $ 0.63   $ 0.54  
  Depreciation, depletion and amortization   $ 3.99   $ 4.05   $ 5.14   $ 4.31   $ 9.15   $ 10.66  
  General and administrative expense(5)   $ 2.87   $ 2.77   $ 3.79   $ 3.49   $ 4.72   $ 4.46  
  Interest expense, net(5)   $ 0.52   $ 0.56   $ 3.24   $ 3.09   $ 7.26   $ 9.46  

(1)
Amounts shown include Marquez Energy from July 1, 2004. See "—Other Accounting Matters—Acquisition of Marquez Energy."

(2)
Includes information for TexCal from March 31, 2006, the date of acquisition. Daily average production volumes shown represent (i) second quarter 2006 production from TexCal properties divided by 91 days plus (ii) first half 2006 production from other Venoco properties divided by 181 days.

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

(4)
Production expenses are comprised of oil and natural gas production expenses and production taxes.

(5)
Net of amounts capitalized.

Comparison of Six Months Ended June 30, 2006 to Six Months Ended June 30, 2005

        Oil and Natural Gas Revenues.    Oil and natural gas revenues increased $40.0 million, or 46%, to $127.4 million for the six months ended June 30, 2006 from $87.4 million for the same period in 2005.

49


The increase was primarily due to production attributable to the TexCal acquisition, partially offset by a 7% decrease in production from other Venoco properties, and higher realized oil prices. The period to period decrease in production volumes from other Venoco properties was primarily due to our sale of the Big Mineral Creek field on March 31, 2005 and from high initial production rates in early 2005 from new offshore oil wells which had recently come on line at that time.

        Oil revenues increased by $26.6 million in the first half of 2006, or 41%, to $90.7 million from $64.2 million in the first half of 2005. Oil production rose 1% with production of 1,606 MBbl in the first half of 2006 compared to 1,583 MBbl in the first half of 2005. The production increase attributable to the TexCal properties was partially offset by an 11% decline in oil production volumes from other Venoco properties. This change resulted primarily from our sale of the Big Mineral Creek field and from high initial production rates in early 2005 from new offshore oil wells that had recently come on line at that time. The Big Mineral Creek field averaged net production of 547 BOE/d in the first quarter of 2005 and was sold on March 31, 2005. Production volumes from other Venoco properties in the first half of 2006 were also negatively impacted relative to the same period in 2005 by the delayed timing of additional saltwater injection facilities, which limited production from some wells in the first quarter of 2006. Our average realized price for oil before hedging losses increased $16.86, or 42%, to $57.31 per Bbl for the first half of 2006. We hedged 68% of our oil production during the period (excluding floors), resulting in realized hedging losses of $8.83 per Bbl and unrealized hedging losses of $11.94 per Bbl. Total hedging losses on oil for the first half of 2006 were $20.77 per Bbl.

        Natural gas revenues increased $13.4 million in the first half of 2006, or 58%, to $36.6 million from $23.2 million in the first half of 2005. Natural gas production increased 54%, with production of 5,764 MMcf compared to 3,732 MMcf in the first half of 2005. The majority of the increase was due to production attributable to the TexCal acquisition. Approximately 5% of the increase resulted from 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 before hedging gains increased $0.14, or 2%, to $6.36 per Mcf for the period. We hedged 53% of our natural gas production during the period (excluding floors), resulting in realized hedging gains of $0.24 per Mcf and unrealized hedging gains of $0.73 per Mcf. Total hedging gains on natural gas were $0.97 per Mcf.

        Commodity Derivatives and Other Revenues.    Realized commodity derivative losses increased $5.6 million, or 79%, to $12.8 million in the first half of 2006 from $7.2 million in the same period in 2005. Unrealized commodity derivative losses were $15.0 million in the first half of 2006, a 47% reduction from the $28.0 million in unrealized commodity derivative losses in the first half of 2005. The changes in commodity derivative losses are due to the effect changes in market prices of oil and natural gas have on our net sales, in the case of realized losses, and the effect of mark to market pricing adjustments on the carrying value of our derivative positions, in the case of unrealized losses. Other revenue also increased 62%, from $2.1 million in the first half of 2005 to $3.4 million in the first half of 2006. This increase was primarily due to revenues of $1.1 million from a pipeline we acquired in the fourth quarter of 2005.

        As a result of the above, total revenues increased $48.7 million, or 90%, to $103.0 million in the first half of 2006 from $54.3 million in the first half of 2005.

        Production Expenses.    Production expenses increased $11.2 million, or 46%, to $35.5 million in the first half of 2006 from $24.3 million in the first half of 2005. The increase was primarily due to production expenses attributable to the TexCal acquisition 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 in timing of production expenses and increased costs of third party services. On a per unit basis, costs increased $2.83 per BOE, from $11.01 per BOE in the first half of 2005 to $13.84 per BOE in the first half of 2006. This increase was

50



partially attributable to remedial work we conducted in the Hastings field. This work, which is expected to be substantially complete in 2006, contributed approximately $1.6 million to production expenses in the second quarter of 2006, and approximately $0.62 per BOE produced in the six-month period ended June 30, 2006. In addition, production expenses on a per BOE basis for other Venoco properties increased 17% due to normal variances in the timing of production expenses and increased costs of third party services.

        Transportation Expenses.    Transportation expenses increased 32%, from $1.2 million in the first half of 2005 to $1.6 million in the first half of 2006. This was primarily attributable to the number of barge shipments of oil from our South Ellwood field in the period and normal timing variances. On a per BOE basis, transportation expenses increased $0.08 per BOE, from $0.55 per BOE in the first half of 2005 to $0.63 per BOE in the first half of 2006.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense increased $14.0 million, or 148%, to $23.5 million in the first half of 2006 from $9.5 million in the first half of 2005. DD&A expense rose $4.84 per BOE, from $4.31 per BOE in the first half of 2005 to $9.15 per BOE in the first half of 2006. This increase is due to higher depletion expense resulting from the increase in the value of our oil and natural gas properties as a result of the TexCal transaction. This is primarily reflected in our second quarter 2006 DD&A rate, which was $10.79 per BOE, as contrasted with $6.63 per BOE in the first quarter of 2006.

        Accretion of Abandonment Liability.    Accretion expense increased $0.1 million, or 9%, to $1.1 million in the first half of 2006 from $1.0 million in the first half of 2005. The increase was due to accretion from the acquired TexCal properties.

        General and Administrative (G&A).    G&A expense increased $4.4 million, or 57%, to $12.1 million in the first half of 2006 from $7.7 million in the first half of 2005. G&A expense rose $1.23 per BOE, or 35%, from $3.49 per BOE in the first half of 2005 to $4.72 per BOE in the first half of 2006. We have increased the depth of our organization in an effort to better position us for growth and to more effectively exploit our asset base by adding professional, technical and support staff, which has contributed to the increase in G&A expenses. Other significant components of the increase include $1.3 million in non-cash compensation expense related to the implementation of FAS 123R in 2006 and $0.8 million of expenses related to TexCal transition and integration activities, which are expected to be completed in 2006. In addition, we incurred $0.7 million in direct costs related to Sarbanes-Oxley Act compliance activities and other indirect costs for internal systems and process conversions intended to position us to more efficiently comply with the Sarbanes-Oxley Act in the future.

        Interest Expense and Amortization of Deferred Loan Costs.    Interest expense, net of interest income and capitalized interest, increased $11.8 million, or 173%, to $18.6 million in the first half of 2006 from $6.8 million in the first half of 2005. The change was primarily due to debt incurred in late March 2006 to acquire TexCal.

        Income tax expense.    Income tax expense in the first half of 2006 was $3.6 million, representing a $2.8 million increase compared to the $0.8 million expense incurred in the first half of 2005. The increase was due to the increase in taxable income in the 2006 period.

        Net Income.    Net income for the first half of 2006 was $5.4 million as compared to net income of $2.0 million in the first half of 2005.

Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004

        Oil and Natural Gas Revenues.    Oil and natural gas revenues increased $51.1 million, or 37%, to $191.1 million for the year ended December 31, 2005 from $140.0 million for 2004. The increase was primarily attributable to rising oil and natural gas prices, which added $43.8 million to oil and natural

51


gas revenues (87%), and an increase in natural gas production, which added $13.1 million to natural gas revenues (26%). Partially offsetting these increases was a decrease in oil production, which decreased oil revenues by $6.8 million (13%).

        Oil revenues increased by $28.2 million in 2005, or 27%, to $134.6 million from $106.4 million in 2004. Oil production fell 5%, with production of 2,953 MBbl in 2005 compared to 3,101 MBbl in 2004, primarily due to the sale of our Big Mineral Creek field. Our average realized price for oil increased $10.97, or 32%, to $45.66 per Bbl for the year. We hedged 71% of our oil production during the year (excluding floors), resulting in realized hedging losses of $7.46 per Bbl and unrealized hedging losses of $10.50 per Bbl. Total hedging losses on oil were $17.96 per Bbl for the year.

        Natural gas revenues increased $22.9 million in 2005, or 68%, to $56.5 million from $33.6 million in 2004. Natural gas production rose 30%, with production of 7,588 MMcf compared to 5,826 MMcf in 2004. Our average realized price for natural gas increased $1.68, or 29%, to $7.45 per Mcf for the year. We hedged 15% of our natural gas production during the year (excluding floors), resulting in realized hedging losses of $0.11 per Mcf and unrealized hedging losses of $0.49 per Mcf. Total hedging losses on natural gas were $0.60 per Mcf for the year.

        Total revenues increased $11.2 million, or 9%, to $138.0 million in 2005 from $126.7 million in 2004. This increase primarily resulted from the 37% increase in oil and natural gas revenues being partially offset by commodity derivative losses of $57.6 million ($22.9 million of which were realized) in 2005 compared to commodity derivative losses of $18.7 million (of which $17.6 million were realized) in 2004.

        Production Expenses.    Production expenses increased $4.4 million, or 9%, to $54.0 million in 2005 from $49.6 million in 2004. This increase was primarily due to increased field activity in 2005 combined with unanticipated expenses associated with the resolution of mechanical problems at a well in the South Ellwood field and periods of limited production capacity due to platform equipment repair and well maintenance. These unanticipated expenses occurred concurrent with a period of reduced production, which resulted in an increase in the per unit costs in 2005 of $0.64 per BOE (from $12.17 per BOE in 2004 to $12.81 per BOE in 2005).

        Transportation Expenses.    Transportation expenses fell by $0.3 million, or 11%, to $2.6 million in 2005 from $2.9 million in 2004. On a per BOE basis, transportation expenses decreased $0.10, or 14%, to $0.62 per BOE from $0.72 per BOE in 2004.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense increased $5.2 million, or 31%, to $21.7 million in 2005 from $16.5 million in 2004. DD&A expense rose $1.09 per BOE on a per unit basis, from $4.05 per BOE in 2004 to $5.14 per BOE in 2005. This was due to changes in estimated future development costs and development costs incurred in 2005 which had the collective effect of increasing the depletion rate per unit. Overall DD&A expense also rose due to increased production volumes.

        Accretion of Abandonment Liability.    Accretion expense rose $0.3 million, or 18%, to $1.8 million in 2005 from $1.5 million in 2004. The increase was due to an increase in abandonment liability associated with additional wells.

        General and Administrative (G&A).    G&A expense increased $4.7 million, or 42%, to $16.0 million in 2005 from $11.3 million in 2004. The largest single component, representing 12% of the increase, is the accrual in December 2005 of a $1.3 million pool for bonuses to be paid to office and administrative staff, including officers, in the second quarter of 2006. This was due to the implementation of more structured and formalized plans relative to prior years, when bonus amounts were less predictable prior to the time of payment. Office and administrative bonuses, including officers' bonuses, determined, accrued and paid in the second quarter of 2005 totaled $0.8 million. The total increase in G&A in 2005

52



also resulted from increases in technical staff, higher professional fees related to accounting and information technology systems conversions and enhancements and the inclusion of expenses of Marquez Energy for all of 2005 as compared to only six months in 2004.

        Interest Expense and Amortization of Deferred Loan Costs.    Interest expense, net of interest income and capitalized interest, increased $11.4 million, or 503%, to $13.7 million in 2005 from $2.3 million in 2004. The change resulted primarily from the increase in indebtedness associated with the issuance of $150.0 million of our senior notes in December 2004. Amortization of deferred loan costs decreased $1.3 million in 2005 compared to 2004. The decrease in amortization was primarily due to a $2.2 million write-off of deferred loan costs in December 2004 related to a reduction in the borrowing capacity under our credit agreement.

        Income tax expense.    Income tax expense in 2005 of $10.3 million represented a decrease of $5.8 million, or 36%, from $16.1 million in 2004. The decrease was primarily due to lower taxable income in the period.

        Net Income.    Net income for 2005 was $16.1 million, compared to $23.5 million for 2004. As discussed above, the largest factors causing the change were the substantial increase in unrealized derivative losses and increased interest expense, partially offset by an increase in oil and natural gas revenues.

Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2003

        Oil and Natural Gas Revenues.    Oil and natural gas revenues increased $30.2 million, or 28%, to $140.0 million for the year ended December 31, 2004 from $109.8 million for the year ended December 31, 2003. The increase was attributable to an increase in oil and natural gas prices, which added $30.1 million (100%) to oil and natural gas revenues, and an increase in natural gas production, which added $1.3 million (4%) to natural gas revenues. Partially offsetting these increases was a decrease in oil production, which decreased oil revenues by $1.2 million (4%).

        Oil revenues increased by $25.0 million, or 31%, to $106.4 million in 2004 from $81.4 million in 2003. This increase was due to an increase in the realized price of oil. Production decreased slightly, with oil production of 3,101 MBbl in 2004 compared to 3,114 MBbl in 2003. Our average realized price for oil increased $5.32, or 22%, to $29.22 per Bbl for 2004. We hedged 53% of our oil production during 2004, resulting in realized hedging losses of $5.47 per Bbl for the year.

        Natural gas revenues increased $5.2 million, or 18%, to $33.6 million in 2004 from $28.4 million in 2003. This increase was due to increases in both natural gas prices and production in 2004 compared to 2003. Our average realized price for natural gas increased 24%, or $1.10, to $5.66 per Mcf, net of hedging, up from $4.56 per Mcf, net of hedging, in 2003. Production increased 4% due to the addition of Marquez Energy's production from July 2004 to the end of the year, production that totaled 461 MMcf.

        Total revenues increased $22.0 million, or 21%, to $126.7 million in 2004 from $104.7 million in 2003. This increase primarily resulted from the 28% increase in oil and natural gas revenues being partially offset by commodity derivative losses of $18.7 million ($17.6 million of which were realized) in 2004 compared to commodity derivative losses of $10.3 million (all of which were realized) in 2003.

        Production Expenses.    Production expenses increased $4.0 million, or 9%, to $49.6 million in 2004 from $45.6 million in 2003. On a per BOE basis, production expenses increased $0.90, or 8%, to $12.17 per BOE in 2004 from $11.27 per BOE in 2003. The increase was due to an increase in general maintenance costs and costs for well rework.

        Transportation Expenses.    Transportation expenses increased $0.1 million, or 5%, to $2.9 million in 2004 from $2.8 million in 2003. On a per BOE basis, transportation expenses increased $0.03, or 4%, to

53



$0.72 per BOE in 2004 from $0.69 per BOE in 2003. The increase was primarily due to higher barge fees in 2004 compared to 2003.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense increased $0.3 million, or 2%, to $16.5 million in 2004 from $16.2 million in 2003. During 2004 and 2003, we incurred impairment losses of $0.1 million and $0.6 million, respectively, related to foreign oil and natural gas properties.

        Accretion of Abandonment Liability.    Accretion expense was $1.5 million in 2004, up slightly from $1.4 million in 2003.

        General and Administrative (G&A).    G&A expense decreased $0.3 million, or 3%, to $11.3 million in 2004 from $11.6 million in 2003. This decrease was primarily due to lower legal and professional fees and settlement costs in 2004. G&A expense does not include amounts capitalized as part of our acquisition, exploitation, development and exploration activities. We capitalized $2.3 million and $3.2 million of G&A expense in 2004 and 2003, respectively. The decrease in capitalized expenses was due to lower staff levels in 2004 compared to 2003.

        Interest Expense and Amortization of Deferred Loan Costs.    Interest expense, net of interest income and capitalized interest, increased $0.1 million, or 7%, to $2.2 million in 2004 from $2.1 million in 2003. The increase was attributable to a higher average level of debt in 2004 compared to 2003. In addition to interest expense, we amortized $3.0 million of deferred loan costs in 2004 compared to $0.4 million in amortization of deferred loan costs in 2003.

        Income Tax Expense.    Our income tax expense for 2004 increased $8.2 million, or 104%, to $16.1 million from $7.9 million for 2003. The increase was primarily due to higher profits in 2004 compared to 2003.

        Net Income.    Our net income before the cumulative effect of change in accounting principle increased $12.7 million, or 118%, to $23.5 million for 2004 from $10.8 million for 2003. The increase was primarily attributable to an increase in oil prices and, to a lesser extent, the increase in natural gas prices. The higher prices for oil and natural gas offset a modest increase in production costs as well as an increase in income tax expenses.

        Other.    In November 2004, we repurchased all of our outstanding preferred stock, consisting of 6,000 shares of mandatorily redeemable convertible preferred plus accrued and unpaid dividends, for $72.0 million. See "Certain Relationships and Related Transactions—Ownership and Related Disputes and Transactions—Repurchase of Preferred Stock from Enron Affiliates." At the time of the purchase of the preferred stock, we had recorded preferred stock and accrued but unpaid dividends net of unamortized issuance costs of $101.9 million. As such, the carrying value of the preferred stock exceeded the repurchase price by $29.9 million.

Liquidity and Capital Resources

        Our primary sources of liquidity are cash generated from our operations and amounts available under our revolving credit facility.

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Cash Flows

 
  Year ended December 31,
  Six Months ended June 30,
 
 
  2003
  2004
  2005
  2005
  2006
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
 
  (in thousands)

 
Cash provided by operating activities   $ 31,557   $ 43,309   $ 39,931   $ 28,221   $ 60,370  
Cash used in investing activities     (10,531 )   (27,990 )   (58,695 )   (46,047 )   (531,262 )
Cash provided by (used in) financing activities     (23,333 )   30,979     (26,562 )   (31,228 )   474,890  

        Net cash provided by operating activities was $60.4 million in the first half of 2006 compared with $28.2 million in the first half of 2005. Cash flows from operating activities during the first half of 2006 were favorably impacted by production attributable to the TexCal transaction and an $8.6 million decrease in cash paid for premiums on derivative contracts.

        Net cash used in investing activities was $531.3 million in the first half of 2006 compared with $46.0 million in the first half of 2005. The primary investing activities in the first half of 2006 include $447.5 million paid in cash to acquire TexCal (net of TexCal cash) and $83.5 million in expenditures for oil and gas properties. The primary investing activities in the first half of 2005 consisted of $14.6 million in expenditures to acquire Marquez Energy and $32.0 million in costs incurred for oil and natural gas properties.

        Net cash provided by financing activities was $474.9 million in the first half of 2006 compared to a use of cash of $31.2 million in the first half of 2005. Proceeds from long-term debt in the first half of 2006 included $350.0 million borrowed under the second lien term loan facility and $139.5 million in net borrowings under the revolving credit facility, which amounts were used to fund the acquisition of TexCal, $14.2 million in loan costs and short-term working capital needs. Net cash used in financing activities in the first half of 2005 primarily consisted of the payment of a $35.0 million dividend to our then-sole stockholder, principal payments on long-term debt of $12.7 million and $5.2 million paid to repurchase common shares, partially offset by $23.0 million in new borrowings.

        Net cash provided by operating activities was $39.9 million in 2005 compared with $43.3 million in 2004. Cash flows from operating activities during 2005 compared to 2004 were favorably impacted primarily by a $51.1 million increase in oil and natural gas sales. This increase resulted from increased production, the acquisition of Marquez Energy and higher commodity prices. Increases in production were partially offset in the second, third and fourth quarters by the loss of production from the Big Mineral Creek field, which was sold on March 31, 2005. Cash flows from operating activities in 2005 as compared to the same period in 2004 were negatively impacted primarily by an $11.9 million increase in payments of net premiums on derivative contracts, an $11.4 million increase in interest costs, a $5.3 million increase in realized commodity derivative losses, a $3.4 million increase in the cash portion of operating and general and administrative expenses and a $4.5 million increase in oil and natural gas production expenses.

        Net cash used in investing activities was $58.7 million in 2005 and consisted primarily of $88.3 million used to develop and acquire oil and natural gas properties other than those of Marquez Energy (comprised of $100.2 million in costs incurred less $11.9 million in accrued amounts payable at December 31, 2005) and $14.6 million used to acquire Marquez Energy, which uses were offset primarily by $44.6 million in net proceeds from the sale of oil and natural gas properties.

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        Net cash used in financing activities was $26.6 million in 2005 compared with net cash provided by financing activities of $31.0 million in 2004. Net cash used in 2005 related primarily to the payment of a $35 million dividend to our then-sole stockholder, $5.3 million used to purchase the interests of minority stockholders and principal repayments on long-term debt of $43.7 million, partially offset by $59.0 million in new borrowings under our credit agreement.

        Net cash provided by operating activities was $43.3 million and $31.6 million for 2004 and 2003, respectively. Operating cash flow increased in 2004 due to higher revenues, which led to higher net income, offset by increased amounts paid for derivative contracts for hedging purposes.

        Net cash used in investing activities was $28.0 million and $10.5 million in 2004 and 2003, respectively, of which $16.3 million and $10.8 million, respectively, related to capital expenditures for drilling and reworking wells, facilities and related costs. During 2003, we began to make quarterly principal and interest payments of $5.8 million with respect to the credit facility then in place. These payments curtailed our ability to make discretionary capital expenditures. Beginning in mid-2004 in connection with the changes in our senior management, we expanded our exploration, exploitation and development activities, which resulted in an increase in cash used in investing activities.

        Net cash provided by financing activities in 2004 was $31.0 million. Net cash provided by financing activities for that year included $272.4 million in proceeds from long term debt, primarily consisting of $146 million in net proceeds from the issuance of our senior notes, $100.7 million in amounts borrowed under our credit agreement and $10.0 million in financing for our new office building. Cash used in financing activities primarily included $159.7 million in repayment of amounts borrowed under our credit agreement and our prior credit facility and $72.0 million for the repurchase of our preferred stock. Net cash used in financing activities was $23.3 million in 2003, comprised entirely of principal payments on the credit facility then in place. We did not increase our borrowings under that facility during 2003.

Capital Resources and Requirements

        We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. We expect that our exploration, exploitation and development capital expenditures in 2006 will be approximately $185 million, including over $30 million on projects acquired as a part of the TexCal transaction. Although our 2007 budget has not yet been finalized, our preliminary expectations are that it will provide for slightly in excess of $200 million in exploration, exploitation and development capital expenditures. However, prior to an offering of our stock in which our net proceeds are at least $200 million, our revolving credit facility would limit capital expenditures to $50 million per quarter, excluding acquisitions. In the first half of 2006, we incurred $83.5 million of capital expenditures on our projects, not including capital expenditures made by TexCal prior to the completion of the TexCal transaction. As a general matter, our strategy is to finance our exploration, exploitation and development capital expenditures primarily with cash flow from operations and to use additional borrowings under our revolving credit facility only for short-term working capital needs, for acquisitions or in other special situations. However, due to the additional debt service obligations we incurred in the TexCal transaction and the additional exploitation and development opportunities we obtained in that transaction, we have used our revolving credit facility more than we otherwise would have to supplement our capital spending since the closing of the transaction. As of October 26, 2006, approximately $188.5 million was outstanding under the revolving credit facility. The revolving credit facility has an aggregate maximum loan amount of $300 million and currently has a borrowing base of $230 million.

        We entered into the revolving credit facility and a second lien term loan facility to finance our acquisition of TexCal. On March 30, 2006, we borrowed $350.0 million pursuant to the second lien term loan facility. On March 31, 2006, we borrowed $119.5 million under the revolving credit facility.

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Principal on the second lien term loan facility is payable on March 30, 2011, and principal on the revolving credit facility is payable on March 30, 2009. Pursuant to mandatory prepayment provisions set forth in the credit facilities, substantially all of the proceeds of asset sales and additional borrowings (except for certain unsecured borrowings and additional borrowings under the revolving credit facility), and up to 50% of the proceeds of equity issuances, must be used to reduce amounts outstanding under one or both facilities. We may from time to time make optional prepayments on outstanding loans. Under the second lien term loan facility, optional prepayments made prior to March 2008 are subject to a prepayment premium.

        Loans made under both facilities are designated, at our option, as either "Base Rate Loans" or "LIBO Rate Loans." Base Rate Loans under the revolving credit facility bear interest at a floating rate equal to (i) the greater of Bank of Montreal's announced base rate and the overnight federal funds rate plus 0.50% plus (ii) a margin ranging from 0.50% to 1.25%, based upon the percentage of the total borrowing base represented by outstanding borrowings. LIBO Rate Loans under the revolving credit facility bear interest at (i) LIBOR plus (ii) a margin ranging from 2.00% to 2.75%, also based upon utilization. A commitment fee ranging from 0.375% to 0.5% per annum is payable with respect to unused borrowing availability under the facility.

        Base Rate Loans under the second lien term loan facility bear interest at a floating rate equal to (i) the greater of the administrative agent's announced base rate and the overnight federal funds rate plus 0.50% plus (ii) 3.50%. LIBO Rate Loans under the second lien term loan facility bear interest at LIBOR plus 4.50%.

        The interest rate margins on both types of loans under each of the revolving credit facility and the second lien term loan facility would decrease 0.50% upon completion of a qualifying IPO, defined as an offering of our common stock in which the net proceeds to us are at least $200.0 million and, for purposes of the second lien term loan facility, if and for so long as our consolidated leverage ratio is less than 3:1.

        The agreements governing the revolving credit facility and the second lien term loan facility contain customary representations, warranties, events of default, indemnities and covenants, including financial covenants that require us to maintain specified ratios of EBITDA to interest expense, current assets to current liabilities, debt to EBITDA and PV-10 to total debt. Our revolving credit agreement also provides that we may not acquire assets with an aggregate value in excess of the aggregate value of assets we sell, and in any event in excess of $15.0 million in any year, until we have completed a public offering of our stock resulting in net proceeds to us of at least $200.0 million. If the net proceeds to us from this offering are less than $200.0 million, we intend to seek an amendment to or waiver of this restriction.

        As of October 26, 2006, amounts outstanding under the credit facilities bore interest at a weighted average rate of 9.24%. Our senior notes bear interest at 8.75%. Debt service obligations under our debt agreements, including the indenture governing our senior notes, totalled approximately $15.5 million for the third quarter of 2006. Our debt service obligations under the credit facilities may increase if market interest rates rise. See "—Quantitative and Qualitative Disclosures About Market Risk."

        Because we must dedicate a substantial portion of our cash flow from operations to the payment of interest on our debt, that portion of our cash flow is not available for other purposes. Our ability to make scheduled interest payments on our indebtedness and pursue our capital expenditure plan will depend to a significant extent on our financial and operating performance, which performance is subject to prevailing economic conditions, commodity prices and a variety of other factors. We intend to use proceeds of this offering to reduce amounts outstanding under our credit facilities and thereby gain greater financial flexibility. See "Use of Proceeds." We are also pursuing a potential sale of certain properties in Texas other than those in the Hastings complex.

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        If our cash flow and other capital resources are insufficient to fund our debt service obligations and our capital expenditure budget, we may be forced to reduce or delay scheduled capital projects, sell material assets or operations or restructure our debt. If cash flow from operations does not meet our expectations, we may reduce the expected level of capital expenditures and/or fund a portion of the expenditures using borrowings under our revolving credit facility or other sources. Until we increase our liquidity, our ability to make significant acquisitions will be limited. If we seek additional capital for that or other reasons, we may do so through traditional reserve base borrowings, joint venture partnerships, asset sales, offerings of debt and equity securities or other means. Needed capital may not be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness and certain other means is limited by covenants in our debt agreements. In addition, pursuant to the mandatory prepayment provisions in our credit facilities described above, our ability to respond to a shortfall in our expected liquidity by selling assets, issuing equity securities or incurring additional indebtedness would be limited by provisions in the facilities that require us to use some or all of the proceeds of such transactions to reduce amounts outstanding under one or both of the facilities. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Commitments and Contingencies

        As of December 31, 2005, the aggregate amounts of contractually obligated payment commitments for the next five years were as follows (in thousands):

 
  Less than One
Year

  1 to 3
Years

  3 to 5
Years

  After 5
years

  Total(2)
Long-term debt(1)   $ 126   $ 20,276   $ 311   $ 158,356   $ 179,069
Interest on senior notes     13,125     26,250     26,250     12,578     78,203
Rental of office space     191     255             446
   
 
 
 
 
Total   $ 13,442   $ 46,781   $ 26,561   $ 170,934   $ 257,718
   
 
 
 
 

(1)
On December 9, 2004, we acquired an office building for $14.2 million. Of the total purchase price, $10.0 million was financed through additional borrowings. Under the agreement with the lender, we are obligated to fund into an account under the control of the lender monthly amounts of approximately $121,000 to cover common area maintenance, improvements, repairs, insurance and taxes, in addition to the monthly mortgage payment. To the extent that funds remain after required expenditures are made, the lender remits any remaining funds to us on a monthly basis in arrears. In March 2006, we paid a dividend to our then-sole stockholder consisting of the membership interests in the entity which owned the building and was liable for the building-related debt. See "Certain Relationships and Related Transactions—Real Property Dividends and Related Transactions—Office Building Dividend."

(2)
Total contractually obligated payment commitments do not include the anticipated settlement of derivative contracts or amounts relating to our asset retirement obligations, which include plugging and abandonment obligations. Our total asset retirement obligations were $22.8 million at December 31, 2005.

        In addition, we have hired a drilling rig for use on platform Gail in the Sockeye field. When we return the rig to the owner, we will be obligated to pay a fee of $252,000. We do not expect to return the rig prior to 2007 at the earliest.

Quantitative and Qualitative Disclosures About Market Risk

        The discussion in this section provides information about derivative financial instruments we use to manage commodity price volatility. Due to the historical volatility of crude oil and natural gas prices,

58



we have implemented a hedging strategy aimed at reducing the variability of the prices we receive for our production and providing a minimum revenue stream. Currently, we purchase puts, sell calls and enter into other derivative transactions such as collars and fixed price swaps in order to hedge our exposure to changes in commodity prices. All contracts are settled with cash and do not require the delivery of a physical quantity to satisfy settlement. While this hedging strategy may result in us having lower revenues than we would have if we were unhedged in times of higher oil and natural gas prices, management believes that the stabilization of prices and protection afforded us by providing a revenue floor is beneficial. We had hedging contracts (excluding floors) in place for approximately 71% of our oil production and approximately 14% of our natural gas production during the year ended December 31, 2005. We had hedging contracts (excluding floors) in place for approximately 68% of our oil production and approximately 53% of our natural gas production during the six months ended June 30, 2006.

        We are subject to interest rate risk with respect to amounts borrowed under our credit facilities because such amounts bear interest at variable rates. At March 29, 2006, immediately prior to the TexCal transaction, we had $10.0 million of indebtedness outstanding under our revolving credit facility. In connection with that transaction, we borrowed an additional $119.5 million under that facility, and we borrowed $350.0 million under the second lien term loan facility. As of October 26, 2006, there was approximately $538.5 million outstanding under those facilities. On May 4, 2006, we entered into an interest rate swap transaction to lock in our interest cost on $200 million of borrowings under the second lien term loan facility at a fixed rate of 9.9225%, including a 4.5% margin, through May 8, 2008. A 1.0% increase in interest rates on unhedged variable rate borrowings of $309.5 million at June 30, 2006 would result in additional annualized interest expense of $3.1 million.

Cumulative Effect of Derivative Transactions

        Oil.    As of June 30, 2006, we had entered into option (including collar) and swap agreements to receive average minimum and maximum NYMEX West Texas Intermediate prices as summarized below. Location and quality differentials attributable to our properties are not reflected in those prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX crude oil price.

 
  Minimum
  Maximum
 
  Bbls/d
  Weighted Avg.
Prices

  Bbls/d
  Weighted Avg.
Prices

Oil hedges at June 30, 2006 for production:                    
July 1—December 31, 2006   10,500   $ 47.85   7,000   $ 59.86
January 1—December 31, 2007   7,313   $ 49.72   6,115   $ 71.58
January 1—December 31, 2008   4,950   $ 54.43   4,950   $ 75.38
January 1—December 31, 2009   4,580   $ 53.94   4,580   $ 76.78

        Natural Gas.    As of June 30, 2006, we had entered into option, swap and collar agreements to receive average minimum and maximum PG&E Citygate prices as follows:

 
  Minimum
  Maximum
 
  MMBtu/d
  Weighted Avg.
Prices

  MMBtu/d
  Weighted Avg.
Prices

Natural gas hedges at June 30, 2006 for production:                    
July 1—December 31, 2006   27,000   $ 7.19   21,000   $ 10.71
January 1—December 31, 2007   21,000   $ 7.42   15,436   $ 11.46
January 1—December 31, 2008   13,500   $ 8.00   11,947   $ 12.24
January 1—December 31, 2009   9,500   $ 7.61   9,500   $ 12.10

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Portfolio of Derivative Transactions

        Our portfolio of commodity derivative transactions as of June 30, 2006 is summarized below:

Oil

Type of Contract

  Basis
  Quantity
(Bbl/d)

  Strike Price ($/Bbl)
  Term
Swap   NYMEX   1,000   $ 57.00 Fixed   Jan 1—Dec 31, 06
Collar   NYMEX   2,000   $ 40.00/$51.00   Jan 1—Dec 31, 06
Collar   NYMEX   1,000   $ 40.00/$51.05   Jan 1—Dec 31, 06
Collar   NYMEX   1,000   $ 40.00/$57.75   Jan 1—Dec 31, 06
Collar   NYMEX   1,500   $ 58.00/$74.60   Apr 1—Dec 31, 06
Collar   NYMEX   500   $ 60.00/$78.70   Apr 1—Dec 31, 06
Put   NYMEX   1,000   $ 40.00 Floor   Jan 1—Dec 31, 06
Put   NYMEX   1,000   $ 42.90 Floor   Jan 1—Dec 31, 06
Put   NYMEX   1,500   $ 57.00 Floor   Jan 1—Dec 31, 06
Collar   NYMEX   2,000   $ 40.00/$65.80   Jan 1—Dec 31, 07
Collar   NYMEX   1,000   $ 40.00/$67.50   Jan 1—Dec 31, 07
Collar   NYMEX   1,000   $ 58.00/$76.25   Jan 1—Dec 31, 07
Collar   NYMEX   1,600   $ 53.00/$75.00   Jan 1—Jun 30, 07
Collar   NYMEX   1,030   $ 53.00/$75.00   Jul 1—Dec 31, 07
Put(1)   NYMEX   2,000   $ 58.00 Floor   Jan 1—Dec 31, 07
Call(2)   NYMEX   566   $ 77.15 Cap   Jan 1—Jun 30, 07
Call(3)   NYMEX   1,035   $ 81.00 Cap   Jul 1—Dec 31, 07
Collar   NYMEX   3,450   $ 52.00/$75.00   Jan 1—Jun 30, 08
Collar   NYMEX   2,450   $ 52.00/$75.00   Jul 1—Dec 31, 08
Collar   NYMEX   1,000   $ 58.00/$78.00   Jul 1—Dec 31, 08
Collar   NYMEX   1,500   $ 58.00/$75.25   Jan 1—Dec 31, 08
Collar   NYMEX   2,170   $ 50.00/$75.00   Jan 1—Jun 30, 09
Collar   NYMEX   1,000   $ 56.00/$79.25   Jul 1—Dec 31, 09
Collar   NYMEX   3,000   $ 55.00/$77.00   Jan 1—Dec 31, 09

(1)
Option premium deferred until each month's settlement period ($3,087,900 total deferred).

(2)
Option premium deferred until each month's settlement period ($405,409 total deferred).

(3)
Option premium deferred until each month's settlement period ($754,206 total deferred).

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Natural Gas

Type of Contract

  Basis
  Quantity
(MMBtu/d)

  Strike Price
($/MMBtu)

  Term
Physical Sale   SoCal   2,000   $ 5.90 Floor (1) 11/01/05—12/31/06
Swap   NYMEX   2,000   $ 6.71 Fixed   Jan 1—Dec 31, 06
Collar   NYMEX   4,000   $ 6.00/$8.50   Jan 1—Dec 31, 06
Collar   NYMEX   6,000   $ 9.00/$15.00   Jan 1—Dec 31, 06
Collar   PG&E Citygate   3,000   $ 7.00/$9.45   Jan 1—Dec 31, 06
Basis Swap   PG&E Citygate   6,000   $ (0.035) (2) Jan 1—Dec 31, 06
Put   PG&E Citygate   6,000   $ 6.00 Floor   Jan 1—Dec 31, 06
Swap   NYMEX   3,000   $ 8.05 Fixed   May 1—Dec 31, 06
Collar   NYMEX   3,000   $ 7.25/$11.70   May 1—Dec 31, 06
Collar   PG&E Citygate   6,000   $ 6.00/$8.40   Jan 1—Dec 31, 07
Collar   NYMEX   5,000   $ 8.00/$14.60   Jan 1—Dec 31, 07
Put(3)   NYMEX   10,000   $ 7.985 Floor   Jan 1—Dec 31, 07
Call(4)   NYMEX   4,564   $ 12.15 Cap   Jan 1—Jun 30, 07
Call(5)   NYMEX   4,310   $ 11.95 Cap   Jul 1—Dec 31, 07
Put(6)   NYMEX   6,000   $ 8.00 Floor   Jan 1—Dec 31, 08
Call(7)   NYMEX   4,513   $ 12.15 Cap   Jan 1—Jun 30, 08
Call(8)   NYMEX   4,382   $ 10.60 Cap   Jul 1—Dec 31, 08
Collar   NYMEX   7,500   $ 8.00/$12.75   Jan 1—Dec 31, 08
Swap   NYMEX   1,250   $ 8.72 Fixed   Jan 1—Jun 30, 09
Collar   NYMEX   1,250   $ 7.75/$13.05   Jan 1—Jun 30, 09
Swap   NYMEX   1,250   $ 8.00 Fixed   Jul 1—Dec 31, 09
Collar   NYMEX   1,250   $ 7.25/$11.30   Jul 1—Dec 31, 09
Collar   NYMEX   7,000   $ 7.50/$12.75   Jan 1—Dec 31, 09

(1)
The price of this contract is the first of the month NGI SoCal Border Index less $0.10 per MMBtu, with a floor of $5.899.

(2)
This basis swap locks the $6.71 NYMEX swap into a $6.675 PG&E Citygate location swap and the $6.00-$8.50 collar into a $5.965-$8.465 collar with a PG&E Citygate location for 2006.

(3)
Option premium deferred until each month's settlement period ($3,650,000 total deferred).

(4)
Option premium deferred until each month's settlement period ($776,465 total deferred).

(5)
Option premium deferred until each month's settlement period ($745,445 total deferred).

(6)
Option premium deferred until each month's settlement period ($2,755,980 total deferred).

(7)
Option premium deferred until each month's settlement period ($928,153 total deferred).

(8)
Option premium deferred until each month's settlement period ($911,203 total deferred).

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        Since June 30, 2006 and through October 25, 2006, we entered into additional derivative transactions as summarized below.

Type of Contract

  Basis
  Quantity(1)
  Strike Price
($/MMBtu)

  Term
Basis Swap (natural gas)   PG&E Citygate   10,000   $ (0.580) (2) Jan 1—Dec 31, 07
Basis Swap (natural gas)   PG&E Citygate   10,000   $ (0.460) (2) Jan 1—Dec 31, 07
Basis Swap (natural gas)   PG&E Citygate   10,000   $ (0.320) (2) Jan 1—Dec 31, 08
Basis Swap (natural gas)   PG&E Citygate   10,000   $ (0.380) (2) Jan 1—Dec 31, 08
Collar (oil)   NYMEX   1,000 (3) $ 60.00/$72.80   Jan 1—Dec 31, 10
Collar (oil)   NYMEX   3,500 (3) $ 60.00/$73.00   Jan 1—Dec 31, 10
Collar (natural gas)   NYMEX   10,000   $   7.00/$10.35   Jan 1—Dec 31, 10
Basis Swap (natural gas)   PG&E Citygate   10,000   $ 0.220 (2) Jan 1—Dec 31, 10

(1)
Except as otherwise indicated, amounts shown are in MMBtu/d.

(2)
Basis swaps lock in the PG&E Citygate location differential deducted from the NYMEX Last Day Settlement Price for natural gas.

(3)
Amounts shown are in Bbl/d.

        We enter into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. The objective of our hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. Our hedging activities mitigate our exposure to price declines and allow us the flexibility to continue to execute our capital plan even if prices decline. Our collar and swap contracts, however, prevent us from receiving the full advantage of increases in oil or natural gas prices above the maximum fixed amount specified in the hedge agreement. Also, if production is less than the amount we have hedged and the price of oil or natural gas exceeds a fixed price in a hedge contract, we will be required to make payments against which there are no offsetting sales of production. This could impact our ability to fund future capital expenditures. In addition, we have incurred, and may incur in the future, substantial unrealized commodity derivative losses in connection with our hedging activities, although we do not expect such losses to have a material affect on our ability to fund expected capital expenditures. Finally, the use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.

        In order to qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedge instrument is no longer considered highly effective.

        All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or confirmed by the counterparty. Changes in the fair value of the effective portion of the cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), which is later transferred to the income statement as a component of commodity derivative income (loss) when the hedged transaction occurs. Changes in the fair value of derivatives that do not qualify as a hedge or are not designated as a hedge, as well as the ineffective portion of hedge derivatives, are recorded in commodity derivative income (loss) on the income statement. We determine hedge ineffectiveness based on changes during the period in the price differentials between the index price of the derivative contracts (which uses a NYMEX index in the case of oil hedges, and NYMEX and PG&E Citygate in the case of natural gas hedges) and the contract price for the point of sale for the cash flow that is being hedged. Hedge ineffectiveness occurs only if the cumulative gain or loss on the derivative hedging instrument exceeds the cumulative change in the expected future cash

62



flows on the hedged transaction. Ineffectiveness is recorded in earnings to the extent the cumulative changes in fair value of the actual derivative exceed the cumulative changes in fair value of the hypothetical derivative.

Changes in Fair Value

        The fair value of outstanding oil and natural gas commodity derivative instruments and the change in fair value that would be expected from a $5.00 per Bbl increase in the price of oil and a $1.00 per MMBtu increase in the price of natural gas are shown in the table below (in millions):

 
  June 30, 2006
 
 
  Fair Value
  Effect of
$5.00/Bbl and
$1.00/MMbtu
Price Increases

 
Effective portion of derivatives designated as cash flow hedges   $ (22.8 ) $ (22.1 )
Derivatives not designated as hedging instruments and the ineffective portion of derivatives designated as cash flow hedges   $ (33.5 ) $ (30.3 )

        The fair value of the swaps and option contracts are estimated based on quoted prices from independent reporting services compared to the contract price of the agreement, and approximate the cash gain or loss that would have been realized if the contracts had been closed out at period end. All hedge positions offset physical positions exposed to the cash market. None of these offsetting physical positions are included in the above table. Price risk sensitivities were calculated by assuming across-the-board increases in price of $5.00 per Bbl for oil and $1.00 per MMBtu for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative portfolio would typically change by less than the amount shown in the table due to lower volatility in out-month prices. In the event of actual changes in all months equal to the assumptions, the fair value of our derivative portfolio would typically change by less than the amount shown in the table due to the fact that many of the changes would be within the range of our derivative collars where the movement in fair value would typically be less than the changes in commodity prices.

        With respect to oil, we had, as of June 30, 2006, NYMEX put options with a weighted average strike price of $48.11 per Bbl on 3,500 Bbl/d in the third and fourth quarters of 2006. With respect to natural gas, we had, as of June 30, 2006, put options with a weighted average strike price of $6.00 per MMBtu on 6,000 MMBtu/d in the third and fourth quarters of 2006. These put options cost an average of $2.83 per Bbl and $0.46 per MMBtu for the third and fourth quarters of 2006 (a total of $4.6 million), which was paid when the put options were contracted. This amount is not included in the fair value of derivatives in the table above.

        See note 5 to our financial statements for a discussion of our long-term debt as of December 31, 2005 and June 30, 2006.

Critical Accounting Policies and Estimates

        Our discussion and analysis of our financial condition and results of operations are based upon financial statements that have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain accounting policies as being of particular importance to the presentation of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and natural gas revenues, oil and natural gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base our estimates on historical experience and various other

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assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies and estimates affect our more significant judgments and estimates used in the preparation of our financial statements:

Reserve Estimates

        Our estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as in the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulation of oil and natural gas that is difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value and the rate of depletion of the oil and natural gas properties. For example, oil and natural gas price changes affect the estimated economic lives of oil and natural gas properties and therefore cause reserve revisions. Our July 31, 2006 estimate of net proved oil and natural gas reserves totaled 94,452 MBOE. Had oil and natural gas prices been 10% lower as of the date of the estimate, our total oil and natural gas reserves would have been 1.7% lower. In addition, our proved reserves are concentrated in a relatively small number of wells. At July 31, 2006, 22% of our proved reserves were concentrated in our twelve largest wells. As a result, any changes in proved reserves attributable to such individual wells could have a significant effect on our total reserves. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Oil and Natural Gas Properties, Depletion and Full Cost Ceiling Test

        We follow the full cost method of accounting for oil and natural gas properties. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and exploitation and development of oil and natural gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and natural gas wells, and salaries, benefits and other internal salary related costs directly attributable to these activities. Proceeds from the disposition of oil and natural gas properties are generally accounted for as a reduction in capitalized costs, with no gain or loss recognized. Depletion of the capitalized costs of oil and natural gas properties, including estimated future development and capitalized asset retirement costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. The capitalized costs are amortized over the life of the reserves associated with the assets, with the amortization being expensed as depletion in the period that the reserves are produced. This depletion expense is calculated by dividing the period's production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the capitalized investment. Changes in our reserve estimates will therefore result in changes in our depletion expense per unit. For example, a 10% reduction in our estimated reserves as of December 31, 2005 would have resulted in an increase of approximately $0.69 per BOE in our depletion expense rate during 2005. Costs associated with production and general corporate activities are expensed in the period incurred. Interest costs related

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to unproved properties and properties under development are also capitalized to oil and natural gas properties. Unproved property costs not subject to amortization consist primarily of leasehold and seismic costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves established or impairment determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as undeveloped areas are tested. Unproved oil and natural gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.

        Capitalized costs of oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the last day of the relevant quarter, including the effects of cash flow hedges, and requires a write down for accounting purposes if the ceiling is exceeded. At December 31, 2005, our net capitalized costs did not exceed the ceiling. We last incurred a write down due to the ceiling test at the end of 1998, at which time our net capitalized cost exceeded the ceiling by $6.5 million, net of income tax effects, and we recorded a write down of our oil and natural gas properties in that amount.

Asset Retirement Obligations

        Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). SFAS 143 provides that, if the fair value for asset retirement obligations can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and natural gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by SFAS No. 143, the retirement obligation is recorded as a liability at its estimated present value at the asset's inception, with the offsetting charge to property cost. Periodic accretion of discount of the estimated liability is recorded in the income statement. Prior to adoption of SFAS No. 143, we accrued for future abandonment costs of wells and related facilities through our depreciation calculation in accordance with Regulation S-X Rule 4-10 and industry practice. This method resulted in recognition of the obligation over the life of the property on a unit-of-production basis, with the estimated obligation netted in property cost as part of the accumulated depreciation, depletion and amortization balance.

        Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our properties at the end of their productive lives, in accordance with applicable laws. We have determined our asset retirement obligation by calculating the present value of estimated cash flows related to each liability. The discount rates used to calculate the present value varied depending on the estimated timing of the relevant obligation, but typically ranged between 6% and 8%. We periodically review the estimate of costs to plug, abandon and remediate our properties at the end of their productive lives. This includes a review of both the estimated costs and the expected timing to incur such costs. We believe most of these costs can be estimated with reasonable certainty based upon existing laws and regulatory requirements and based upon wells and facilities currently in place. Any changes in regulatory requirements, which changes cannot be predicted with reasonable certainty, could result in material changes in such costs. Changes in the reserve estimates as discussed above and the economic life of oil and natural gas properties could affect the timing of such costs and accordingly the present value of such costs.

Income Tax Expense

        Income taxes reflect the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also

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recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying current tax rates to the differences between financial statement and income tax reporting. We have not recognized a valuation allowance against our net deferred taxes because we believe that it is more likely than not that the net deferred tax assets will be realized based on estimates of our future operating income.

Derivative Instruments

        Under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended, we reflect the fair market value of our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes from third parties, as well as utilizing a Black-Scholes option valuation model that is based upon underlying forward price curve data, a risk-free interest rate and estimated volatility factors. Changes in commodity prices will result in substantially similar changes in the fair value of our commodity swap agreements, and in substantially similar changes in the fair value of our commodity collars to the extent the changes are outside the floor or cap of our collars.

Other Accounting Matters

Push-Down Accounting

        During 2004, our Chairman and CEO, Timothy Marquez, increased his beneficial ownership of our outstanding stock from 41% to 100%. Mr. Marquez acquired 53% of the shares of common stock then outstanding from two of our former officers and their respective affiliates in a transaction that closed on July 12, 2004. On December 22, 2004, we merged with a corporation the sole stockholder of which was the Marquez Trust. In the merger, the trust acquired the remaining 6% of our common stock and as a result now owns all of our outstanding common stock.

        As a result of Mr. Marquez obtaining control of over 95% of the common stock on December 22, 2004, SEC Staff Accounting Bulletin No. 54 requires the acquisition by Mr. Marquez to be "pushed-down," meaning our post-transaction condensed consolidated balance sheet and the condensed consolidated statements of operations and cash flows reflect a new basis of accounting. The pre-transaction condensed consolidated statements of operations and cash flows are presented on a historical basis.

Acquisition of Marquez Energy

        Because Marquez Energy was a company under common control since July 12, 2004, our financial statements and production information include Marquez Energy from July 1, 2004 (results during the period between July 1 and July 12, 2004 were de minimis). The acquisition was accounted for in a manner similar to a pooling of interests whereby the historical results of Marquez Energy were combined with our financial results. Accordingly, of the total purchase price for Marquez Energy of $16.8 million, $9.8 million was charged to equity for the excess of the purchase price over Mr. Marquez' historical basis (net of deferred tax assets of $3.7 million), oil and natural gas properties were written up by $3.7 million to fair value for amounts paid to minority interests, and equity was credited for $0.4 million to eliminate the minority interests in Marquez Energy. The production information included in this prospectus also includes Marquez Energy from July 1, 2004. However, Marquez Energy's proved reserves as of December 31, 2004 are not included in our proved reserves as of that date.

Recent Accounting Pronouncements

        In December 2004, the FASB issued Statement of Accounting Standard 153, Exchanges of Nonmonetary Assets ("SFAS 153"), an amendment of Accounting Principles Board ("APB") Opinion 29 that eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance.

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We do not expect SFAS 153 to have a material effect on our consolidated financial position or results of operations.

        In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations ("FIN 47"). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The adoption of FIN 47 did not have any impact on the financial statements because we do not have any conditional asset retirement obligations that we have not accrued for.

        In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, which replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. APB Opinion No. 20 previously required that most voluntary changes in an accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. SFAS No. 154 now requires retrospective application of changes in an accounting principle to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The Statement is effective for fiscal years beginning after December 15, 2005. We adopted SFAS No. 154 effective January 1, 2006 and the adoption could have a material impact on our financial position and results of operations if we have an accounting change.

        In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an Amendment of FASB Statements No. 133 and 140 ("SFAS 155"). This statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133") and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities and resolves issues addressed in SFAS 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interest in Securitized Financial Assets." This Statement (i) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, (ii) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, (iii) establishes a requirement to evaluate beneficial interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, (iv) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and (v) eliminates restrictions on a qualifying special-purpose entity's ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires a presentation within the financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value of those instruments. We are required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although early adoption is permitted as of the beginning of an entity's fiscal year. We are evaluating the provisions of SFAS 155. The effects of adopting of SFAS 155 on our financial statements are not known at this time.

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BUSINESS AND PROPERTIES

        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. We believe that California's numerous large oil and natural gas fields and limited number of well capitalized, independent operators present us with an attractive niche market opportunity. Our principal properties are located offshore southern California, onshore in California's Sacramento Basin and along the Gulf Coast of Texas, and are characterized by long reserve lives, predictable production profiles and substantial opportunities for further exploitation and development, including numerous relatively low risk drilling locations. Our strategy is to:

    leverage our experience, expertise and relationships in California;

    exploit our multi-year inventory of drilling locations;

    acquire properties with low-risk exploitation and development opportunities at attractive prices;

    reduce unit operating costs by increasing reserves and production; and

    pursue relatively low-risk, opportunistic exploration activities.

        We have grown to become one of the largest independent oil and natural gas companies in California based on production volumes. In furtherance of our growth strategy, we acquired TexCal for $456 million in cash on March 31, 2006. As a result of the transaction, we have strengthened our position as the most active driller in the Sacramento Basin, a principal growth area for us, and have reestablished our presence in Texas. According to reserve reports prepared by NSAI and DeGolyer & MacNaughton, we had proved reserves of approximately 94.5 MMBOE as of July 31, 2006, of which 57% were oil and 57% were proved developed. The PV-10 value of our pro forma proved reserves as of that date was approximately $1.7 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 "Non-GAAP Financial Measures and Reconciliations" beginning on page 12. Our average net production in the second quarter of 2006 was 17,114 BOE/d, implying a proved reserves to production ratio of 15.1 years.

Our History

        Timothy Marquez, our Chairman and CEO, founded our company in 1992 together with a business associate. We acquired the Whittier and Santa Clara Avenue fields in 1994, the Beverly Hills field in 1995 and the Willows, Grimes and Big Mineral Creek fields in 1996. In 1997, we purchased the South Ellwood field, our first offshore property. We operated with very limited equity capital until 1998, when we issued $60 million of preferred stock to two affiliates of Enron Corp. We completed four additional acquisitions the same year. In 1999, we acquired three additional offshore properties, including the Sockeye field. In 2001, we were named by Inc. magazine as one of the 200 fastest-growing private companies in the United States.

        In June 2002, in connection with a dispute between us and the Enron affiliates, Mr. Marquez's business associate, our former CFO and the directors nominated by the Enron affiliates gained control of the board of directors. The board then terminated Mr. Marquez's employment and appointed Mr. Marquez's business associate as CEO. In May 2004, he and the former CFO agreed to sell all their stock in the company to Mr. Marquez, and Mr. Marquez returned as CEO in June 2004. Following his purchase of shares from his business associate and the former CFO, Mr. Marquez owned approximately 94% of our outstanding common stock. In November 2004, we repurchased all of our preferred stock from the Enron affiliates. In December 2004, we issued $150.0 million of our senior notes and effected a merger pursuant to which the Marquez Trust acquired all of our outstanding common stock. Since Mr. Marquez's return as CEO, we have returned to our historical policy of devoting substantial resources to exploration, exploitation and development projects on our properties. Our exploration,

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exploitation and development capital expenditures rose from $23.2 million in 2004 to $83.6 million in 2005. In addition, since Mr. Marquez's return, we have completed eight acquisitions, including TexCal, for a total purchase price of $489 million.

Our Strengths and Strategy

        Our principal competitive strengths and the key elements of our business strategy are described in "Summary—Our Strengths" and "Summary—Our Strategy," respectively.

Description of Properties

        The following table summarizes our proved reserves by area and related information as of July 31, 2006, as derived from reserve reports prepared by NSAI and DeGolyer & MacNaughton.

 
  Proved Reserves
(MMBOE)

  % of Total
Reserves

  % Oil
  PV-10 Value
($MM)

  % of Total
PV-10

 
Coastal California                        
  South Ellwood   23.1   24.4 % 82 % $ 490.0   28.8 %
  Santa Clara Federal Unit   13.5   14.3 % 95 % $ 342.9   20.2 %
  Dos Cuadras   3.6   3.8 % 84 % $ 49.9   2.9 %
  Onshore   2.4   2.5 % 93 % $ 51.3   3.0 %
Sacramento Basin                        
  Greater Grimes   23.6   24.9 %   $ 321.5   18.9 %
  Willows   2.2   2.4 %   $ 31.4   1.8 %
  Other   2.7   2.9 %   $ 29.7   1.8 %
Texas                        
  Hastings Complex   13.4   14.2 % 100 % $ 180.8   10.6 %
  Constitution   2.0   2.1 % 45 % $ 70.0   4.1 %
  Other   8.0   8.5 % 30 % $ 134.5   7.9 %
   
 
 
 
 
 
Total   94.5   100 % 56.7 % $ 1,701.8   100 %
   
 
 
 
 
 

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. We acquired our interest from Mobil Oil Corporation in 1997. Since that time, we have made numerous operational enhancements to the field, including an additional well, reworks of existing wells and upgrades at the platform and the associated 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 June 30, 2006, we had 21 producing wells and three injection wells in the field. During June 2006, average net production at the field was 3,374 Bbl/d of oil and 3,718 Mcf/d of natural gas. We completed an exploration well on platform Holly to the Sespe formation in the second half of 2005. This well is currently producing at marginal rates. A second exploration well was drilled late in 2005 to the north flank of the Monterey formation. This well was dry and will be converted into a water injection well in the future. In the second half of 2006, we plan to install electric submersible pumps on four wells on the platform. We completed seven workovers in the field in the first six months of 2006, of which six were successful.

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        We own processing and transportation facilities at South Ellwood, including 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 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. Oil produced at the South Ellwood field has been transported by barge since operations at the field commenced in 1966. 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. The barge has historically delivered the oil primarily to Long Beach, California for purchase by Shell. However, Shell informed us in August 2006 that it was not willing to accept further deliveries from this barge at its Long Beach terminal. In response to Shell's decision, we have sold recent shipments of oil production from the field to a refinery in the San Francisco area on a shipment-by-shipment basis. That refinery is not obligated to accept more than two additional deliveries of approximately 53,000 Bbls each. Moreover, the average price we received from the sales to that refinery was approximately $15.31 less per Bbl than we received from Shell, and the associated transportation costs were approximately $0.59 higher per Bbl (in each case based on sales through September 30, 2006). We are evaluating potential alternative delivery and sales arrangements, including entering into a long-term contract with a buyer other than Shell. We are also pursuing the possibility of using an onshore pipeline instead of a barge, but construction of the pipeline would require governmental approvals and would not be completed before 2008 at the earliest. Any alternative arrangement for delivery and sale of the production may require time to implement and may require us to accept lower prices for our production from the field and/or incur higher transportation costs. See "Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry—The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not control. For our largest field, we rely on one barge, which is currently out of service, to transport production from the field. When these facilities or systems are unavailable, our operations can be interrupted and our revenues reduced." Natural gas produced at the field is transported by common carrier pipeline.

        On October 20, 2006, the barge by which we deliver oil produced from the South Ellwood field was involved in a minor collision with a tugboat and is currently out of service for repair and inspection. Because we have limited storage capacity for oil produced from the field, we have been required to significantly curtail production at the field. Although we expect that the barge will be back in operation in the first week of November 2006, if it does not return to operation as expected, we will be required to shut in production from the field. Any such shut in would adversely affect our financial condition and results of operations.

        In addition to our processing and transportation facilities, we operate, and have a 78% interest in, two seep tents located in the vicinity of the drilling platform. These tents capture naturally seeping natural gas from the ocean floor at a net rate of approximately 200 Mcf/d. The captured natural gas is transported to the onshore facility by a separate pipeline. The seep tents have helped to reduce air emissions and contain the flow of naturally occurring natural gas seeps onto the Santa Barbara coastline.

        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 field 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,

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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 June 30, 2006, we had 18 producing wells and four active injection wells in the field. The primary producing horizons initially were the Monterey and Upper Sespe. More recently, recompletions in the Upper Topanga horizon have accounted for a larger share of production. 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 June 2006, average net production at the field was 3,352 Bbl/d of oil and 1,195 Mcf/d of natural gas.

        We believe that additional drilling opportunities exist in the Sockeye field and have identified approximately ten locations for potential drilling and three recompletion opportunities. In the first half of 2006, we drilled one dual completion well with production from the Lower Topanga/Sespe and Upper Topanga formations and one well to an untested structure with potential for Monterey, Upper Topanga and Sespe production. The latter well was dry at its deep target depth and is currently being tested in uphole zones. If the well is successful, another similar structure to the southwest will be drilled at a later date. In addition, 3D seismic surveys have identified structures to the south and southwest which are fault-separated from the current development and untested. Using current technology, these structures can be reached from platform Gail and could provide additional drilling locations.

        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. We are evaluating the possible return of platform Grace to production through the redrilling of selected wells and upgrades to facilities. We do not currently expect to generate significant production from the platform before the second half of 2007 at the earliest. In March 2003, we granted an option to Crystal Energy LLC to lease or purchase platform Grace for use as a liquid natural gas, or LNG, terminal. In March 2006, Crystal Energy assigned its interest in the option agreement to Clearwater Port LLC, that agreement was terminated and we entered into a new agreement with Clearwater. Under the new agreement, Clearwater has an option to purchase or lease platform Grace for use as an LNG terminal. The option will become exercisable on January 1, 2008 and will expire on March 1, 2012. If Clearwater exercises the option, we will cease any exploration, exploitation and development activities then conducted from the platform and Clearwater will commence construction of its LNG facility. Clearwater'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, Clearwater will pay us an annual fee during the period in which the LNG facility is being constructed. This annual fee will initially be $6 million, and will increase over time to a potential maximum of $10 million. Following the commencement of operations at the facility, Clearwater 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 million for the first 800,000 MMBtu per day and $0.04 per MMBtu for volumes in excess of 800,000 MMBtu/d on an average annual basis.

        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 DCOR, LLC. Production is transported via pipeline to Los Angeles, California. As of June 30, 2006, there were 85 producing wells and 17 injection wells in the field. During June 2006, average net production at the field was 604 Bbl/d of oil and 375 Mcf/d of natural gas.

        Onshore Coastal California.    Our onshore properties in the coastal California region include the Beverly Hills West field, which 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

71



Beverly Hills high school. We acquired our interest in the field from Wainoco Oil & Gas Company in 1995. We operate the field and have a 100% working interest. Another onshore field in the coastal California region is the Santa Clara Avenue field, which is located in Ventura County, California. We acquired our interest in this field in 1994 and 1996 from three other operators. We operate the field and have working interests ranging from 43% to 100%. During June 2006, aggregate average net production from our onshore coastal California properties was 446 Bbl/d of oil and 365 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, containing nine of the state's ten largest natural gas fields by that measure. It is located near northern California natural gas markets and has substantial natural gas gathering infrastructure and pipeline capacity. It is approximately 210 miles long and 60 miles wide and contains a variety of different geologic plays. We were the most active driller in the basin in 2005 and we believe that, on a pro forma basis as of December 31, 2005, we had the largest acreage position in the area. We are also one of the largest producers in the area, with average net production of 32,438 Mcf/d in June 2006. We own 3D seismic data covering 500 square miles in the basin and are in the process of analyzing the 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. In the first half of 2006, we drilled and completed 23 new wells and completed 36 successful workovers and recompletions in the basin. In addition, we drilled three dry wells and had one unsuccessful recompletion. We currently have three drilling rigs and two completion/workover rigs under contract 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 73,684 net acres as of June 30, 2006, including 49,483 net acres acquired in the TexCal transaction. We operate substantially all of the fields and have an average working interest of 60%.

        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. We had 253 producing wells and two injection wells in the fields as of June 30, 2006.

        At the time we acquired our initial interests in the fields from Mobil Oil Corporation in 1996, production was approximately 5,400 Mcf/d. As a result of significant acquisition, exploration, exploitation and development activities in the fields since mid-2004, average net production rose to approximately 27,031 Mcf/d in June 2006. To date, we have focused primarily on the Greater Grimes field, where we drilled 27 wells and completed 23 from June 2004 through June 2006. We completed 13 infill wells in the Willows field in the first six months of 2006. We completed 42 workovers in the fields in 2005 and 37 in the first half of 2006. We believe that there are significant additional opportunities for infill drilling and workovers in the fields and in surrounding areas.

        Other Sacramento Basin.    We have a number of other fields in the Sacramento Basin, located in Solano, Contra Costa, San Joaquin and Colusa Counties. We operate each of these fields and have working interests ranging from 42% to 100%. As of June 30, 2006, we had a total of 30 active 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 the fields was approximately 5,406 Mcf/d in June 2006.

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Texas

        Hastings Complex.    Our largest property in Texas is the Hastings complex, which encompasses approximately 4,684 net acres located approximately 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 field and the Hastings field. We operate the entire complex.

        The Hastings complex produces light, sweet crude oil with a gravity of 30.6 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 June 30, 2006, we had 118 producing wells in the complex. During June 2006, average net production from the complex was approximately 1,852 Bbl/d of oil. We are currently in the process of returning approximately 30 idle wells to production and upgrading artificial lift systems on approximately 20 additional wells. We completed 26 reworks in the complex in the second quarter of 2006. We also purchased six square miles of 3D seismic data covering a portion of the complex to help us evaluate additional drilling opportunities. In addition, we plan to a pursue a water injection project in selected fault blocks.

        We are evaluating a potential CO2 enhanced recovery project in the Hastings complex. CO2 injection is an efficient tertiary recovery mechanism used to increase the recovery of crude oil from mature fields. Although we are at an early stage in our evaluation process, we believe that the project may have the potential to increase the oil reserves in the field. The success of any CO2 enhanced recovery project will depend on, among other things, our ability to obtain an economic and reliable supply of CO2 and our ability to develop the internal and/or external expertise necessary to implement the project.

        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 June 30, 2006, there were three producing wells in the field. During June 2006, average net production from the field was approximately 116 Mcf/d of natural gas and 43 Bbl/d of oil. We are currently in the process of acquiring 3D seismic data covering 13 square miles of the field. Subject to further evaluation of this data, we plan to drill two wells in the field in late 2006 or early 2007.

        Other.    Our other Texas properties encompass a total of 10,303 net acres in the southern Gulf Coast region. Our average working interest in these fields is 92% and we operate substantially all of our production there. As of June 30, 2006, there were a total of 65 producing wells in these fields. Total average net production from the fields in June 2006 was 272 Bbl/d of oil and 2,864 Mcf/d of natural gas. In the second half of 2006, we plan to drill one well in our Giddings field. In addition, we are preparing to shoot 13.5 square miles of 3D seismic data in our Liberty South field. To date in 2006, we have drilled two wells in our Word field.

Oil and Natural Gas Reserves

        The following table sets forth our net proved reserves for the dates indicated on a historical and pro forma basis. Our reserve estimates as of December 31, 2003 are based on a reserve report prepared by Ryder Scott, our reserve estimates as of December 31, 2004 and 2005 are based on reserve reports prepared by NSAI and our reserve estimates as of July 31, 2006 are based on reserve reports prepared by NSAI and DeGolyer & MacNaughton. Proved reserves as of each date indicated reflect all acquisitions and dispositions completed as of that date. The pro forma column combines our historical estimates of net proved oil and natural gas reserves as of December 31, 2005 with those of TexCal as determined by DeGolyer & MacNaughton as of that date. The reserve estimates were based upon

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those engineers' review of production histories and other geological, economic, ownership and engineering data.

 
  December 31,
  Pro Forma as of December 31, 2005
   
 
  July 31,
2006

 
  2003
  2004(1)
  2005
Net proved reserves (end of period)                    
Oil (MBbl)                    
  Developed   31,423   28,035   24,154   36,973   39,428
  Undeveloped   15,334   11,900   11,146   13,002   14,137
   
 
 
 
 
    Total   46,757   39,935   35,300   49,975   53,565
   
 
 
 
 
Natural gas (MMcf)                    
  Developed   51,112   49,418   53,390   81,947   84,467
  Undeveloped   15,473   20,458   20,663   92,208   160,856
   
 
 
 
 
    Total   66,585   69,876   74,053   174,155   245,323
   
 
 
 
 

Total proved reserves (MBOE)

 

57,855

 

51,581

 

47,642

 

79,000

 

94,452
   
 
 
 
 

(1)
Does not include reserves of Marquez Energy. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Accounting Matters—Acquisition of Marquez Energy." The amount shown does include 3.4 MMBOE of proved reserves attributable to the Big Mineral Creek field, which we sold on March 31, 2005.

        As of July 31, 2006, our proved reserves totaled 94,452 MBOE (56.7% proved developed), comprised of 53,565 MBbl of oil (56.7% of the total) and 245,323 MMcf of natural gas, and had an estimated proved reserves to production ratio of 15.1 years.

        Proved reserves are estimates of oil and natural gas to be recovered in the future. Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs, or from existing wells where relatively major expenditure is required for completion.

        Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Future prices received for the sale of oil and natural gas will likely be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserve estimates are often different, and may differ materially, from the quantities of oil and natural gas that are ultimately recovered.

        Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The present value shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to the timing of future production that may prove to be inaccurate. For properties that we operate, expenses exclude our share of overhead charges. In addition, the calculation of estimated future net revenues does not take into account the effect of various cash outlays, including, among other things, general and administrative costs, interest expense and income taxes.

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Production, Prices and Costs

        The following table sets forth certain information regarding our average net production volumes, average sales prices realized and certain expenses associated with sales of oil and natural gas for the periods indicated on a historical and pro forma basis. We urge you to read this information in conjunction with the information contained in our financial statements and related notes included elsewhere in this prospectus. The information set forth below is not necessarily indicative of future results.

 
  Historical
  Pro Forma
 
 
   
   
   
  Six
Months
ended
June 30,
2006(2)

   
  Six
Months
ended
June 30,
2006

 
 
  Year ended December 31,
   
 
 
  Year ended December 31,
2005

 
 
  2003
  2004(1)
  2005(1)
 
Production Volume                                      
  Natural gas (MMcf)     5,607     5,826     7,588     5,764     12,442     7,570  
  Oil (MBbls)     3,114     3,101     2,953     1,606     3,728     1,797  
  MBOE     4,049     4,072     4,218     2,567     5,802     3,059  
Daily Average Production Volume                                      
  Natural gas (Mcf/d)     15,362     15,918     20,789     42,031     33,938     41,823  
  Oil (Bbl/d)     8,532     8,472     8,090     9,982     10,104     9,928  
  BOE/d     11,092     11,125     11,555     16,987     15,760 (3)   16,899  
Oil Price per Bbl Produced (in dollars)                                      
  Realized price before commodity derivative loss   $ 26.29   $ 34.69   $ 45.66   $ 57.31   $ 47.52   $ 57.79  
  Realized commodity derivative loss     (2.39 )   (5.47 )   (7.46 )   (8.83 )   (6.49 )   (7.77 )
   
 
 
 
 
 
 
  Net realized   $ 23.90   $ 29.22   $ 38.20   $ 48.48   $ 41.03   $ 50.02  
   
 
 
 
 
 
 
Natural Gas Price per Mcf Produced (in dollars)                                      
  Realized price before commodity derivative gain (loss)   $ 5.06   $ 5.77   $ 7.45   $ 6.36   $ 7.76   $ 7.01  
  Realized commodity derivative gain (loss)     (0.50 )   (0.11 )   (0.11 )   0.24     (0.15 )   0.18  
   
 
 
 
 
 
 
  Net realized   $ 4.56   $ 5.66   $ 7.34   $ 6.60   $ 7.61   $ 7.19  
   
 
 
 
 
 
 
Average Sale Price per BOE(4)   $ 24.69   $ 30.42   $ 39.55   $ 44.15   $ 42.63   $ 46.33  
Expense per BOE                                      
  Production expenses(5)   $ 11.27   $ 12.17   $ 12.81   $ 13.84   $ 13.14   $ 13.75  
  Transportation expenses     0.69     0.72     0.62     0.63     0.48     0.54  
  Depreciation, depletion and amortization     3.99     4.05     5.14     9.15     9.55     10.66  
  General and administrative expense(6)     2.87     2.77     3.79     4.72     3.44     4.46  
  Interest expense, net(6)     0.52     0.56     3.24     7.26     9.73     9.46  

(1)
Amounts shown include Marquez Energy from July 1, 2004. See "Management's Discussion and Analysis of Financial Conditions and Results of Operations—Other Accounting Matters—Acquisition of Marquez Energy."

(2)
Includes information for TexCal from March 31, 2006, the date of acquisition. Daily average production volumes shown represent (i) second quarter 2006 production from TexCal properties divided by 91 days plus (ii) first half 2006 production from other Venoco properties divided by 181 days.

(3)
Excludes production from the Big Mineral Creek field, which we sold in March 2005. Average net production from the field was 547 BOE/d in the first quarter of 2005, or 135 BOE/d for 2005 as a whole.

(4)
Amounts shown are based on oil and natural gas sales, net of inventory changes and realized commodity derivative losses, divided by sales volumes.

(5)
Production expenses are comprised of oil and natural gas production expenses and production taxes.

(6)
Net of amounts capitalized.

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Drilling Activity

        The following table sets forth information with respect to development and exploration wells we drilled from January 1, 2003 through June 30, 2006 on a historical basis (including Marquez Energy from the time we acquired it in March 2005). The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells. Fluid injection wells for waterflood and other enhanced recovery projects are not included as gross wells. The number of net wells is the sum of fractional working interests we own in our gross wells expressed as whole numbers and fractions thereof. A producing well is a well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. A dry well is not a producing well.

 
  Development Wells Drilled
 
  2003
  2004
  2005
  2006(1)
Producing                
  Gross     4.0   16.0   11.0
  Net     3.8   7.9   8.3
Dry                
  Gross       1.0   1.0
  Net       0.2   0.7

 


 

Exploration Wells Drilled

 
  2003
  2004
  2005
  2006(1)
Producing                
  Gross     2.0   3.0   16.0
  Net     1.4   1.9   12.0
Dry                
  Gross     1.0   5.0   3.0
  Net     0.5   3.2   2.5

(1)
Through June 30, 2006.

        The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered.

Oil and Natural Gas Wells

        The following table details our working interests in producing wells as of June 30, 2006. Well counts include wells with multiple completions. Wells are classified as oil or natural gas wells according to the predominant production stream.

 
  Gross
producing
wells

  Net
producing
wells

  Average
working
interest

 
Oil   329   227.0   69.0 %
Natural gas   295   189.8   64.3 %
   
 
 
 
  Total   624   416.8   66.8 %
   
 
 
 

Acreage

        The following table summarizes our estimated developed and undeveloped leasehold acreage as of June 30, 2006. Developed acreage is assigned to producing wells. Undeveloped acreage is acreage held under lease, permit, contract or option that is not assigned to a producing well, including leasehold interests identified for exploratory drilling. Gross acres refers to the total number of acres in which we

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own a working interest. Net acres refers to gross acres multiplied by our fractional working interest. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

 
  Developed
  Undeveloped(1)
  Total
Area

  Gross
  Net
  Gross
  Net
  Gross
  Net
Coastal California                        
  South Ellwood   1,543   1,543   6,174   6,174   7,717   7,717
  Santa Clara Federal Unit   8,640   8,640   25,920   23,040   34,560   31,680
  Dos Cuadras   881   219   4,994   1,241   5,875   1,460
  Paredon(2)       5,812   4,096   5,812   4,096
  Onshore   1,722   1,340   26,910   18,203   28,632   19,543
   
 
 
 
 
 
Sacramento Basin   33,989   25,231   103,311   83,560   137,300   108,790
Texas   7,747   6,830   11,117   8,504   18,864   15,334
   
 
 
 
 
 
  Total   54,522   43,803   184,238   144,818   238,760   188,621
   
 
 
 
 
 

(1)
Ninety percent of our historical undeveloped leasehold acreage is, by the terms of the applicable lease(s), held by production from the other producing wells and is not subject to expiry unless production ceases. The Paredon leases, totaling a net 4,096 acres, are subject to expiry in 2013 and 2014.

(2)
Paredon is a non-producing prospect and there are no proved reserves associated with the property.

Legal Proceedings

        In the ordinary course of our business, we are named, from time to time, as a defendant in various legal proceedings. We maintain liability insurance and believe that our coverage is reasonable in view of the legal risks to which our business is ordinarily subject.

Beverly Hills Litigation

        Between June 2003 and April 2005, six lawsuits were filed against us and certain other energy companies in the Los Angeles County Superior Court by persons who attended Beverly Hills High School or who are citizens of Beverly Hills/Century City or visitors to that area during the time period running from the 1930s to date. There are approximately 1,000 plaintiffs (including plaintiffs in two related lawsuits in which we have not been named) who claim to be suffering from various forms of cancer or other illnesses, fear they may suffer from such maladies in the future, or are related to persons who have suffered from cancer or other illnesses. Plaintiffs allege that exposure to substances in the air, soil and water that originated from either oil-field or other operations in the area are the cause of the cancers and other maladies. We have owned an oil and natural gas facility adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before we owned the facility. It is anticipated that additional plaintiffs may be added to the litigation over time. All cases have been consolidated before one judge. The judge has ordered that all of the cases be stayed except for an initial trial group consisting of twelve "representative" plaintiffs. Discovery relating to the initial trial group is ongoing, with a trial set for November 2006. We believe that the claims made in the suits are without merit, but we cannot predict the outcome of the suits. We are vigorously defending the actions, and will continue to do so until they are resolved. We also have defense and indemnity obligations to certain other defendants in the actions who have asserted claims for indemnity for events occurring after we acquired the property in 1995. In addition, certain defendants have made claims for indemnity for events occurring prior to 1995, which we are disputing. We cannot predict the cost of defense and indemnity obligations at the present time.

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        One of our insurers is currently paying for the defense of these lawsuits under a reservation of its rights. Two other insurers that provided insurance coverage to us (the "Declining Insurers") have taken the position that they are not required to provide coverage for losses arising out of, or to defend against, the lawsuits because of a pollution exclusion contained in their policies. The Beverly Hills School District (the "District"), as an additional insured on those policies, brought a declaratory relief action against those insurers in Los Angeles County Superior Court. In November 2005, the court ruled in favor of one of the insurers. The District is appealing that decision. On July 10, 2006, the same Los Angeles County Superior Court denied a motion for summary judgment brought by another of the insurers against the District on the issue of the duty to defend. On February 10, 2006, we filed our own declaratory relief action against the Declining Insurers in Santa Barbara County Superior Court seeking a determination that those insurers have a duty to defend us in the lawsuits. The policy issued by the insurer that is currently providing defense of the lawsuits contains a pollution exclusion similar to that at issue in the actions brought against the Declining Insurers. However, we have no reason to believe that the insurer currently providing defense of these actions will cease providing such defense. If it does, and we are unsuccessful in enforcing our rights in any subsequent litigation, we may be required to bear the costs of the defense, and those costs may be material. If it is ultimately determined that the pollution exclusion or another exclusion contained in one or more of our policies applies, we will not have the protection of those policies with respect to any damages or settlement costs ultimately incurred in the lawsuits.

        In accordance with SFAS No. 5, Accounting for Contingencies, we have not accrued for a loss contingency relating to the Beverly Hills litigation because we believe that, although unfavorable outcomes in the proceedings may be reasonably possible, we do not consider them to be probable or reasonably estimable. If one or more of these matters are resolved in a manner adverse to us, and if insurance coverage is determined to not be applicable, their impact on our results of operations, financial position and/or liquidity could be material.

Personal Injury Claims

        In February 2006, a complaint was filed in Santa Barbara Superior Court against us on behalf of a boy who had been severely injured after falling from a cliff located on property jointly owned by us and another company. The complaint asserts that we are responsible for the boy's injuries and that the boy is entitled to damages, including reimbursement of past medical expenses, future expenses, loss of earning capacity and general damages. We believe that we have no liability in this matter and intend to defend the action vigorously.

        On March 31, 2006, a complaint was filed in District Court in Madison County, Texas against a subsidiary of ours by the widow of an individual who was fatally injured while working as a gauger/pumper at a well operated by the subsidiary. The cause of the accident is still being investigated.

Regulatory Environment

        Our oil and natural gas exploration, production and transportation activities are subject to extensive regulation at the federal, state and local levels. These regulations relate to, among other things, environmental and land use matters, conservation, safety, pipeline use, the drilling and spacing of wells, well stimulation, transportation, and forced pooling and protection of correlative rights among interest owners. The following is a summary discussion of some key regulations that affect our operations.

Environmental and Land Use Regulation

        A wide variety of environmental and land use regulations apply to companies engaged in the production and sale of oil and natural gas. These regulations have been changed frequently in the past, and in general, these changes have imposed more stringent requirements that increase operating costs and/or require capital expenditures in order to remain in compliance. We believe that our business

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operations are in substantial compliance with current laws and regulations. Failure to comply with these requirements can result in civil and/or criminal fines and liability for non-compliance, clean-up costs and other environmental damages. It is also possible that unanticipated developments or changes in law could require us to make environmental expenditures significantly greater than those we currently expect.

        California Environmental Quality Act ("CEQA").    CEQA is California legislation that requires consideration of the environmental impacts of proposed actions that may have a significant effect on the environment. CEQA requires the responsible governmental agency to prepare an environmental impact report that is made available for public comment. The responsible agency is also required to consider mitigation measures. The party requesting agency action bears the expense of the report.

        We are currently in the CEQA process in connection with, among other things, our requested renewal of the state lease for the marine terminal at the South Ellwood field. A public draft of the environmental impact report relating to the request has been issued and the issuance of a final report is pending.

        We may be required to undergo the CEQA process for other lease renewals and other proposed actions by state and local governmental authorities that meet specified criteria. At a minimum, the CEQA process delays, and adds expense to, the process of obtaining new leases, permits and lease renewals.

        Discharges to Waters.    The Federal Water Pollution Control Act of 1972, as amended (the "Clean Water Act"), and comparable state statutes impose restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into regulated waters and wetlands. These controls have generally become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. These laws prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal and offshore waters without appropriate permits.

        The Clean Water Act also regulates stormwater discharges from industrial properties and construction activities and requires separate permits and implementation of a stormwater management plan establishing best management practices, training, and periodic monitoring with respect to covered activities. Certain operations are also required to develop and implement "Spill Prevention, Control, and Countermeasure" plans or facility response plans to address potential oil spills. Certain exemptions from some Clean Water Act requirements have been created or broadened pursuant to the Energy Policy Act of 2005.

        The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. It also imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into regulated waters.

        Oil Spill Regulations.    The Oil Pollution Act of 1990, as amended, or OPA, amends and augments the provisions of the Clean Water Act relating to oil spills, imposing potentially unlimited liability on responsible parties, without regard to fault, for the costs of cleanup and other damages resulting from an oil spill in U.S. waters. Responsible parties include (i) owners and operators of onshore facilities and pipelines and (ii) lessees or permittees of offshore facilities. In addition, the OPA requires parties responsible for offshore facilities to provide financial assurance in the amount of $35 million, which can be increased to $150 million in some circumstances, to cover potential OPA liabilities.

        Regulations imposed by the Minerals Management Service, or MMS, also require oil spill response plans and oil spill financial assurance from offshore oil and natural gas operations, whether operating in state or federal offshore waters. These regulations were designed to be consistent with the OPA and

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other similar requirements. Under MMS regulations, operators must join a cooperative that makes oil spill equipment available to its members. The California Department of Fish and Game, Office of Oil Spill Prevention and Response, or OSPR, has adopted overlapping oil spill prevention regulations. We have complied with these OPA, MMS and OSPR requirements by adopting an offshore oil spill contingency plan and becoming a member of Clean Seas, LLC, a cooperative entity operated with other offshore operators to prevent and respond to oil spills in the offshore region in which we operate.

        Air Emissions.    Our operations are subject to local, state and federal regulations governing emissions of air pollution. Local air quality districts are responsible for much of the regulation of sources of air pollutants in California. California requires new and modified stationary sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally-based permitting requirements. Because of the severity of the ozone (smog) problems in portions of California, the state has the most severe restrictions on the emissions of volatile organic compounds, or VOCs, and nitrogen oxides, or NOx, of any state. Producing wells, natural gas plants and electric generating facilities all generate VOCs and NOx. Some of our producing wells are in counties that are designated as nonattainment for ozone and are therefore potentially subject to restrictive emission limitations and permitting requirements. California also operates a stringent program to control hazardous (toxic) air pollutants, and this program could result in the required installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission sources. Air emissions from oil and natural gas operations also are regulated by oil and natural gas permitting agencies, including the MMS, the State Lands Commission and other local agencies.

        Waste Disposal.    We currently own or lease a number of properties that have been used for production of oil and natural gas for many years. Although we believe the prior owners and/or operators of those properties utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties that we currently own or lease. State and federal laws applicable to oil and natural gas wastes and properties have become more stringent. Under new laws, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial well plugging operations to prevent future, or mitigate existing, contamination.

        We may generate wastes, including "solid" wastes and "hazardous" wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, although certain oil and natural gas exploration and production wastes currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our oil and natural gas operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly operating, disposal and clean-up requirements. State and federal oil and natural gas regulations also provide guidelines for the storage and disposal of solid wastes resulting from the production of oil and natural gas, both onshore and offshore.

        Superfund.    Under some environmental laws, such as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, also known as CERCLA or the Superfund law, and similar state statutes, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated substances ("hazardous substances") at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA

80



and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of hazardous substances, in the course of our operations we may have generated and may generate wastes that fall within CERCLA's definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties.

        Abandonment, Decommissioning and Remediation Requirements.    Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production and transportation facilities and the environmental restoration of operations sites. MMS regulations, coupled with applicable lease and permit requirements and each property's specific development and production plan, prescribe the requirements for decommissioning our federally leased offshore facilities. The California State Lands Commission, or CSLC, and the California Department of Conservation, Division of Oil, Gas and Geothermal Resources, or DOGGR, are the principal state agencies responsible for regulating the drilling, operation, maintenance and abandonment of all oil and natural gas wells in the state, whether onshore or offshore. MMS regulations require federal leaseholders to post performance bonds. See "—Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations—Plugging and Abandonment Costs" for a discussion of our principal obligations relating to the abandonment and decommissioning of our facilities.

        California Coastal Act.    The California Coastal Act regulates the conservation and development of California's coastal resources. The California Coastal Commission (the "Coastal Commission") works with local government to make permit decisions for new developments in certain coastal areas and reviews local coastal programs, such as land use restrictions. The Coastal Commission also works with the California State Office of Oil Spill Prevention and Response to protect against and respond to coastal oil spills. The Coastal Commission has direct regulatory authority over offshore oil and natural gas development within the state's three mile jurisdiction and has authority, through the Federal Coastal Zone Management Act, over federally permitted projects that affect the state's coastal zone resources. We conduct activities that may be subject to the California Coastal Act and the jurisdiction of the Coastal Commission.

Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations

        Significant potential costs relating to environmental and land use regulations associated with our existing properties and operations include those relating to (i) plugging and abandonment of facilities, (ii) clean-up costs and damages due to spills or other releases and (iii) civil penalties imposed for spills, releases or non-compliance with applicable laws and regulations. As is customary in the oil and natural gas industry, we typically have contractually assumed, and may assume in the future, regulatory obligations relating to plugging and abandonment, clean-up and other environmental costs in connection with our acquisition of operating interests in fields, and these costs can be significant.

        Plugging and Abandonment Costs.    Our operations, and in particular our offshore platforms and related facilities, are subject to stringent abandonment and closure requirements imposed by the MMS and the state of California. With respect to the Santa Clara Federal Unit, Chevron retained most of the abandonment obligations relating to the platforms and facilities when it sold the fields to us in 1999. We are responsible for abandonment costs relating to the wells and to any expansions or modifications we made following our acquisition of the fields. We also agreed to assume from Chevron all

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abandonment obligations associated with its 25% interest in the infrastructure (but not the wells) in the Dos Cuadras field. We agreed to assume all of the abandonment costs relating to the operations, including platform Holly, in the South Ellwood field when we purchased it from Mobil Oil Corporation in 1997.

        As described in note 13 to our financial statements, we have estimated the present value of our aggregate asset retirement obligations to be $22.6 million as of December 31, 2005 and $34.4 million as of June 30, 2006 (including $9.2 million in obligations attributable to the acquisition of TexCal). These figures reflect the expected future costs associated with site reclamation, facilities dismantlement and plugging and abandonment of wells. The discount rates used to calculate the present value varied depending on the estimated timing of the obligation, but typically ranged between 6% and 8%. Actual costs may exceed our estimates. Our financial statements do not reflect any reserves relating to other environmental obligations.

        Under a variety of applicable laws and regulations, including CERCLA, RCRA and MMS regulations, we could in some circumstances be held responsible for abandonment and clean-up costs relating to our operations, both onshore and offshore, notwithstanding contractual arrangements that assign responsibility for those costs to other parties.

        Clean-up Costs.    We currently have two onshore facilities with known environmental contamination. Our onshore facility at the South Ellwood field is known to have hydrocarbon contamination. We are currently required to provide quarterly monitoring reports to the county. Because oil occurs naturally in the area, regulators have not yet determined the appropriate level of clean-up for this facility. We expect that we will generally be permitted to defer remedial actions with respect to the facility until we cease operations there, and our present intention is to continue using it for the foreseeable future. We currently estimate that the cost of a clean-up of the facility will be between $2.0 and $5.0 million. These costs are included in the asset retirement obligation shown in our financial statements. For the purpose of calculating the asset retirement obligation, we estimated that the facility has a remaining useful life of 20 years. The onshore oil and natural gas plant associated with the Santa Clara Federal Unit is also known to have hydrocarbon contamination. Chevron is contractually obligated to remediate the contamination that was present at the time we purchased the property upon the closure of that facility. We will be responsible for the clean-up of any additional contamination. To our knowledge, no such additional contamination has occurred. Accordingly, we do not currently expect to incur any remediation costs in connection with this facility.

        Penalties for Non-Compliance.    We believe that our operations are in material compliance with all applicable oil and natural gas, safety, environmental and land use laws and regulations, and we work diligently to ensure continuing compliance. However, from time to time we receive notices of noncompliance with Clean Air Act and other requirements from relevant regulatory agencies.

        We received an Order of Abatement from the Santa Barbara County Air Pollution Control District, or SBCAPCD, in 1999 regarding odor complaints and hydrogen sulfide (H2S) emissions from our operations in the South Ellwood field. That order required us to implement various odor prevention measures, conduct safety audits, adopt a quality assurance plan and take certain other actions. The requirements set forth in the order have been or are being satisfied. Since 2001, we have received several Notices of Violation, or NOVs, from SBCAPCD for minor air quality violations at the South Ellwood field, but those NOVs have been or are expected to be resolved for minimal civil penalties. SBCAPCD's air quality regulations are among the most stringent in the country. We believe that our working relationship with SBCAPCD is generally good.

        We have received several NOVs related to air emissions from our Beverly Hills operations from the South Coast Air Quality Management District, or SCAQMD. These NOVs were resolved pursuant to a settlement agreement reached in October 2003. In June 2004, SCAQMD issued an additional NOV to us for fugitive natural gas emissions from wellhead components following an unplanned, automated electrical shutdown at the Beverly Hills field. That NOV remains unresolved, but we expect

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the matter to be resolved without a major financial penalty or other material impact. A June 2004 Air Toxics Inventory Report and Health Risk Assessment conducted by us and submitted to SCAQMD for the Beverly Hills facilities concluded that the air emissions from these operations do not exceed applicable risk or action levels and are typical of the ambient air in the Los Angeles air basin.

        On November 18, 2004, there was a natural gas and oil release from a wellhead on platform Gail. Our investigation of this release has been completed and the U.S. Coast Guard and the MMS have indicated that they are satisfied with our response. The MMS issued two NOVs that require us to take certain minor remedial actions and, in March 2006, informed us that it is seeking to impose a fine of $30,000 in connection with the release. The Coast Guard has indicated that it will not impose any financial penalty on us with respect to the release.

        On February 24, 2005, a minor release of water containing some oil occurred from our Beverly Hills facility. The release was contained quickly, but a small amount of water and oil sprayed off-site. We notified the appropriate agencies following the release. We do not expect that significant financial or other penalties will be assessed with respect to the release.

        In 2005, we received a total of 13 NOVs from applicable regulatory agencies, including those described above. Of this total, ten have been resolved without significant financial or other penalties. We received one NOV in the first half of 2006, which is currently pending. We do not expect to incur significant penalties with respect any outstanding NOV.

Other Regulation

        The pipelines we use to gather and transport our oil and natural gas are subject to regulation by the U.S. Department of Transportation, or DOT, under the Hazardous Liquids Pipeline Safety Act of 1979, as amended, or HLPSA, and the Pipeline Safety Act of 1992, which relate to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Under the Pipeline Safety Act, the Research and Special Programs Administration of DOT is authorized to require certain pipeline modifications as well as operational and maintenance changes. We believe our pipelines are in substantial compliance with HLPSA and the Pipeline Safety Act. Nonetheless, significant expenses could be incurred if new or additional safety requirements are implemented.

        The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act, as well as the Natural Gas Policy Act. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis.

        The rates, terms, and conditions applicable to the interstate transportation of oil by pipelines are also regulated by FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil pipelines to fulfill the requirements of Title VIII of the Energy Policy Act of 1992, comprised of an indexing system to establish ceilings on interstate oil pipeline rates. FERC has announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000 concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC's pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

        With respect to transportation of natural gas on the Outer Continental Shelf, or OCS, FERC requires, as a part of its regulation under the Outer Continental Shelf Lands Act, or OCSLA, that all pipelines provide open and non-discriminatory access to both owner and non-owner shippers.

        Our OCS leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. Under certain circumstances, the MMS may require any of our

83



operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

        Our offshore leases in state waters or "tidelands" (within three miles of the coastline) are administered by the state of California and require compliance with certain regulations of the CLSC and DOGGR. The CSLC serves as the lessor of our state offshore leases and is charged with overseeing leasing, exploration, development and environmental protection of the state tidelands.

        Commencing with the Cunningham-Shell Act of 1955, California has enacted several pieces of legislation that withhold state tidelands from oil and natural gas leasing. The Cunningham-Shell Act protected an area of tidelands offshore Santa Barbara County that stretches west from Summerland Bay to Coal Oil Point, and included waters offshore the unincorporated area of Montecito, the City of Santa Barbara, and the University of California at Santa Barbara. It also protected the state tidelands around the islands of Anacapa, Santa Cruz, Santa Rosa, and San Miguel. In 1994, California enacted the California Sanctuary Act which, with three exceptions, prohibits leasing of any state tidelands for oil and natural gas development. Oil and natural gas leases in effect as of January 1, 1995 are unaffected by this legislation until such leases revert back to the state, at which time they will become part of the California Coastal Sanctuary. This legislation does not restrict our existing state offshore leases or our current or planned future operations.

        The safety of our operations is primarily regulated by the MMS, the CSLC, the Coast Guard and the Occupational Safety and Health Administration ("OSHA"). We believe our facilities and operations are in substantial compliance with the applicable requirements of those agencies. In the event different or additional safety measures are required in the future, we could incur significant expenses to meet those requirements.

Operating Hazards and Insurance

        The oil and natural gas business involves a variety of operating risks, such as those described under "Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry—Our Business Involves Significant Operating Risks That Could Affect Our Production and Could Be Expensive To Remedy." In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us.

Title to Properties

        We believe that we have satisfactory title to all of our material assets. Title to our properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry. However, we believe that none of these liens, restrictions, easements, burdens and encumbrances materially detract from the value of our properties or from our interest in those properties or materially interfere with our use of those properties in the operation of our business. We believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus. Our debt agreements are secured by liens on substantially all of our oil and natural gas properties and other assets. See "Description of Indebtedness."

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Marketing and Major Customers

        Markets for oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. All of our oil production is sold to competing buyers, including large oil refining companies and independent marketers. In the year ended December 31, 2005, approximately 68% and 29% of our oil production was sold to ConocoPhillips and Shell Trading (US) Co., respectively, pursuant to agreements with pricing based on the NYMEX WTI price minus a fixed differential and/or California posted prices plus fixed premiums. In the year ended December 31, 2005, TexCal sold approximately 44% of its oil production to BP/Amoco, 23% to Gulfmark Energy, 16% to Teppco and 12% to Sunoco. TexCal's sales were made pursuant to agreements with pricing based on WTI posted prices plus spot, monthly premiums.

        In California, we sell substantially all of our natural gas production to large marketing companies pursuant to agreements that provide for monthly index pricing and/or daily pricing. In the year ended December 31, 2005, we sold 51% and 27% of our California natural gas production to Enserco Energy, Inc. and Chevron, respectively. In the year ended December 31, 2005, TexCal sold 72% and 21% of its California natural gas production to Chevron Natural Gas and Enserco Energy, Inc., respectively. In Texas, we sell substantially all of our natural gas production to large marketing companies pursuant to long term agreements using a combination of monthly index pricing and market adjustments. In the year ended December 31, 2005, TexCal sold approximately 48% of its Texas natural gas production to ETC Texas Pipeline, 28% to Houston Pipeline Company and 11% to Duke Energy Field Services.

Competition

        The oil and natural gas business is highly competitive in the search for and acquisition of additional reserves and in the sale of oil and natural gas. Our competitors principally consist of major and intermediate sized integrated oil and natural gas companies, independent oil and natural gas companies and individual producers and operators. Our competitors include Plains Exploration & Production Company and Berry Petroleum Company. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop our properties. These competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.

Offices

        We currently lease approximately 23,000 square feet of office space in Denver, Colorado, where our principal office is located. The lease for the Denver office expires in 2013. We lease an additional 39,000 square feet of office space in Carpinteria, California from 6267 Carpinteria Avenue, LLC. The lease for the Carpinteria office will expire in 2019. As described in "Certain Relationships and Related Transactions," 6267 Carpinteria Avenue, LLC was a wholly owned subsidiary of ours prior to March 2006, when we paid a dividend consisting of 100% of the membership interests in 6267 Carpinteria Avenue, LLC to our then-sole stockholder. The lease remains in effect following the payment of the dividend. We also lease approximately 28,500 square feet of office space in Houston, where we maintain a regional office. We believe that our office facilities are adequate for our current needs and that additional office space can be obtained if necessary.

Employees

        As of June 30, 2006, we had approximately 231 full-time employees, none of whom were party to collective bargaining arrangements.

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MANAGEMENT

Directors and Executive Officers

        The following table sets forth certain information with respect to our directors and executive officers as of September 30, 2006.

Name

  Age
  Position
Timothy Marquez   48   Chairman and Chief Executive Officer
William Schneider   45   President
David B. Christofferson   58   Chief Financial Officer
Mark DePuy   51   Senior Vice President, Chief Operating Officer
Terry L. Anderson   59   General Counsel and Secretary
Douglas J. Griggs   47   Chief Accounting Officer
J. Timothy Brittan(1)   51   Director
J.C. "Mac" McFarland(1)(2)   59   Director
Ed O'Donnell(3)   52   Director
Eloy Ortega(1)(3)   55   Director
Joel L. Reed(2)(3)   55   Director
Glen C. Warren, Jr.(2)   50   Director

(1)
Member of the compensation committee.

(2)
Member of the audit committee.

(3)
Member of the corporate governance/nominating committee.

        Timothy Marquez co-founded Venoco in September 1992 and served as our CEO from our formation until June 2002. He founded Marquez Energy 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. See "Certain Relationships and Related Transactions—Ownership and Related Disputes and Transactions." 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.

        William Schneider became our President in January 2005. Prior to joining us, Mr. Schneider was a managing director at BMO Capital Markets (formerly known as Harris Nesbitt), an investment bank, where he focused on mergers and acquisitions in the energy industry. He joined BMO Capital Markets in February 2001. From January 1998 to January 2001, he worked in the Energy Investment Banking division of Donaldson, Lufkin & Jenrette. Mr. Schneider's experience also includes service in Smith Barney's Energy Investment Banking division. Before entering investment banking, Mr. Schneider held a variety of engineering and corporate positions at Unocal for over 12 years. Mr. Schneider holds an M.B.A. in Finance from U.C.L.A. and a B.S. in petroleum engineering from the Colorado School of Mines.

        David B. Christofferson became our CFO in November 2004. Mr. Christofferson was CFO of Marquez Energy from November 2002 until joining our company in his current capacity. Prior to joining Marquez Energy, Mr. Christofferson served as General Counsel and CFO of Esenjay Exploration, Inc. (f/k/a Frontier Natural Gas Corporation), a NASDAQ-listed company, from 1988 until May 2002. Between May and November 2002, he was a private consultant. Mr. Christofferson holds B.A. and J.D. degrees from the University of Oklahoma and a Master of Divinity degree from Phillips University (now a part of the University of Tulsa).

        Mark DePuy became our Vice President, Northern Assets, in August 2005 and was promoted to Senior Vice President and Chief Operating Officer in January 2006. Prior to joining us, he spent

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27 years with Unocal in a variety of domestic and international operating and business planning roles, most recently as a corporate planning manager for worldwide operations. With Unocal, Mr. DePuy spent 13 years working on operations onshore and offshore coastal California. He has an M.B.A. from U.C.L.A. and a B.S. in petroleum engineering from the Colorado School of Mines.

        Terry L. Anderson is our General Counsel and Secretary. Mr. Anderson joined us in March 1998 and served as General Counsel until June 2002. From July 2002 to August 2004, Mr. Anderson was in private practice in Santa Barbara, California. He returned in his current capacities in August 2004. Mr. Anderson holds a B.S. in petroleum engineering and a J.D. from the University of Southern California. Mr. Anderson was Vice President and General Counsel of Monterey Resources, Inc., a NYSE-listed company, from August 1996 to January 1998. Prior to that, he was chief transactional attorney for Santa Fe Energy Resources in Houston, Texas. Mr. Anderson is licensed to practice law in Texas and California.

        Douglas J. Griggs was appointed as our Chief Accounting Officer in January 2006. Mr. Griggs is a certified public accountant with twenty-five years of accounting and financial management experience, including 13 years with Ernst & Young LLP. From January 2003 through December 2005, he was an independent consultant in the areas of finance, accounting, project management and Sarbanes-Oxley compliance. From 1997 to December 2002, he served as Chief Financial Officer for Engineered Data Products, Inc. Mr. Griggs has an accounting degree from the University of Northern Iowa.

        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.

        J.C. "Mac" McFarland has been a director of Venoco since June 2004. He has 28 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 Advisers, 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.

        Ed O'Donnell has been a director of Venoco since June 2004. He was also a member of our board of directors from May 2001 to December 2002, and from May 2003 to August 2003. In addition, from 1997 to March 2001, he served as Vice President and, from April 2001 to June 2002, as the President of our domestic division. He took a sabbatical from July 2002 to March 2003, and was an independent small business consultant from April 2003 to July 2004. Since June 2004, he has served as Executive Director and General Manager of Old Mission Santa Barbara, a non-profit organization. He also provides consulting services to us on a part-time basis. In addition, in February 2006, he became the Chief Operating Officer of P-Squared Development, LLC, a firm that provides consulting services to non-profit organizations. In April 2006, he also became the CEO of Gong Zhu Enterprises, a provider of products and services to small retail businesses. He has 20 years of experience with Unocal, including as Asset Manager. Mr. O'Donnell holds a B.S. in petroleum engineering from Montana Tech, an M.S. in petroleum engineering from the University of Southern California and an M.B.A. from Pepperdine University.

        Eloy Ortega has been a director of Venoco since June 2004. He is the President and CEO of Promerica Bank, a Los Angeles-based bank currently in its formation stage. He was President and CEO of Business First National Bank in Santa Barbara, California from October 1999 until September 2005. From 1998 until 1999, Mr. Ortega served as President and CEO of City Commerce Bank. He has over 30 years of experience in the banking industry and has a degree in finance from New Mexico State University.

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        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 Titan Investment Partners, a private equity firm. 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).

        Glen C. Warren, Jr. has been a director of Venoco since June 2004 and has more than 22 years experience in the oil and natural gas industry. He is the President, CFO and a director of Antero Resources Corporation, where he has served in those capacities since June 2002. From November 2001 until June 2002, he was a Managing Director with Concert Energy Advisors. From July 1998 until February 2001, he served as the Executive Vice President and CFO, and as a director, of Pennaco Energy. He took a sabbatical from March to October 2001. He has served as a director of Diamond Foods, Inc. since July 2005. Mr. Warren holds a B.A. in interdisciplinary science and a J.D. from the University of Mississippi and an M.B.A. from U.C.L.A.

Classified Board of Directors

        Our certificate of incorporation provides that our directors are divided into three classes, each serving staggered three-year terms. As a result, stockholders will elect a portion of our board of directors each year. The initial terms of directors in Class I expired at the annual meeting of stockholders held in May 2006 and each of those directors was reelected for a new three-year term. The initial terms of directors in Class II will expire at the annual meeting of stockholders to be held in 2007 and the initial terms of directors in Class III will expire at the annual meeting of stockholders to be held in 2008. Currently, the Class I directors are Messrs. O'Donnell and Brittan, the Class II directors are Messrs. Ortega and Warren and the Class III directors are Messrs. Marquez, McFarland and Reed. The division of our board of directors into classes could delay or prevent a change of control of our company. See "Description of Capital Stock—Certain Anti-Takeover Effects of Provisions of Our Certificate of Incorporation and Bylaws."

Board Committees

        Our bylaws provide that our board of directors may designate one or more board committees. We currently have an audit committee, a compensation committee and a corporate governance/nominating committee. The composition and primary responsibilities of each committee are described below. Each committee operates pursuant to a charter approved by our board of directors. Each member of these committees is independent as defined under the rules of the New York Stock Exchange and applicable SEC rules.

Audit Committee

        Our audit committee's primary function is to oversee our accounting and financial reporting processes and our systems of internal accounting and financial controls, select and retain our outside

88



auditors and facilitate communication among the outside auditors, management and our board of directors. Among other things, the audit committee:

    is responsible for the appointment, compensation and retention of our outside auditors and reviews and evaluates the auditors' qualifications, independence and performance;

    oversees the auditor's audit work and reviews and pre-approves all audit and non-audit services to be performed by the auditors;

    reviews and approves the planned scope of our annual audit;

    reviews our financial statements and discusses with management and the outside auditors the results of the annual audit and the review of our quarterly financial statements; and

    reviews and approves all proposed transactions that would require disclosure pursuant to Item 404 of Regulation S-K or any other transaction involving us and any other person where the parties' relationship is not arms'-length.

        Our audit committee is comprised of Messrs. McFarland (chair), Warren and Reed. Our board of directors has determined that Mr. McFarland qualifies as an "audit committee financial expert" as defined under the rules of the SEC.

Compensation Committee

        Our compensation committee's primary function is to evaluate, approve, administer and interpret our compensation and benefit policies as they affect our executive officers. Among other things, the compensation committee:

    reviews and approves corporate goals and objectives relevant to compensation of our CEO;

    evaluates the performance of the CEO in light of those goals and objectives;

    sets the compensation of the CEO; and

    makes recommendations to the board of directors with respect to the compensation of executive officers other than the CEO.

        Our compensation committee is comprised of Messrs. Ortega (chair), Brittan and McFarland.

Corporate Governance/Nominating Committee

        Our corporate governance/nominating committee's primary function is to assist our board of directors by identifying individuals qualified to become members of the board and by advising the board with respect to corporate governance matters. Among other things, the corporate governance/nominating committee:

    seeks out and identifies individuals qualified to become directors;

    recommends to our board of directors candidates for nomination as directors; and

    monitors and oversees matters of corporate governance, including by developing and recommending corporate governance guidelines applicable to us and monitoring our compliance with those guidelines.

        Our corporate governance/nominating committee is comprised of Messrs. Reed (chair), Ortega and O'Donnell.

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Compensation Committee Interlocks and Insider Participation

        None of our executive officers serves as a member of the board of directors or compensation committee of any entity an executive officer of which serves as a member of our board of directors or compensation committee. Ed O'Donnell, who was a member of our compensation committee during 2005, was an officer of our company from 1997 to 2002 and currently provides consulting services to us on a part-time basis. Mr. O'Donnell resigned from the compensation committee, and was appointed to the corporate governance/nominating committee, in February 2006.

Executive Compensation

Summary Compensation Table

        As of December 31, 2005, Timothy Marquez was our CEO, and our four other most highly compensated executive officers during 2005 were William Schneider, David Christofferson, Terry Anderson and Gregory Schrage. Mr. Schrage is our Vice President of Asset Development. We refer to these officers in this prospectus as the named executive officers. The following table sets forth the compensation we paid to the named executive officers for services rendered in 2004 and 2005.

 
   
  Annual Compensation
   
   
 
Name and Principal Position

   
  Securities
Underlying
Options(#)

  All Other
Compensation($)

 
  Year
  Salary($)
  Bonus($)(1)
 
Timothy Marquez, Chairman and CEO   2005
2004
  361,542
191,637

(3)
578,000
33,034
 
  9,329
7,621
(2)
(4)

William Schneider, President

 

2005
2004

 

255,952

 

163,773

(5)

1,471,162.5

 

9,329

(6)

David Christofferson, CFO

 

2005
2004

 

221,040
27,000


(3)

66,312
32,400

 

547,500

 

7,660

(7)

Terry Anderson, General Counsel and Secretary

 


2005
2004

 


212,853
95,333



(3)


63,856
28,600

 


262,500

 


7,660
38,935


(8)
(9)

Gregory Schrage, VP—Asset
Development

 


2005
2004

 


183,613
155,036

 


37,016
38,759

 


262,500

 


17,579
5,067


(10)
(11)

(1)
We generally pay bonuses in the year following the year in which they were earned. Unless otherwise noted, bonus amounts shown are reported for the year in which they were earned, though they may have been paid in the following year.

(2)
Amount shown is comprised of $660 in insurance premiums and $1,669 in health club dues, in each case paid on Mr. Marquez's behalf, and a $7,000 matching contribution under our 401(k) plan.

(3)
Amount shown represents salary paid for the portion of the year in which the officer was employed by us.

(4)
The amount is comprised of a one-time housing allowance payment of $4,381 and a $3,240 matching contribution under our 401(k) plan.

(5)
Amount shown includes a $25,000 a signing bonus.

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(6)
Amount shown is comprised of $660 in insurance premiums and $1,669 in health club dues, in each case paid on Mr. Schneider's behalf, and a $7,000 matching contribution under our 401(k) plan.

(7)
Amount shown is comprised of $660 in insurance premiums paid on Mr. Christofferson's behalf and a $7,000 matching contribution under our 401(k) plan.

(8)
Amount shown is comprised of $660 in insurance premiums paid on Mr. Anderson's behalf and a $7,000 matching contribution under our 401(k) plan.

(9)
Amount shown is comprised of $32,760 in fees paid for legal services provided by Mr. Anderson in June and July 2004 prior to the commencement of his employment with us and a $6,175 matching contribution under our 401(k) plan.

(10)
Amount shown is comprised of $660 in insurance premiums paid on Mr. Schrage's behalf, $7,849 in respect of vacation time forgone, a $7,000 matching contribution under our 401(k) plan and $2,071 in respect of stock options that were terminated in connection with the merger described in "Certain Relationships and Related Transactions—Ownership and Related Disputes and Transactions—Merger with Marquez Trust."

(11)
Amount shown is comprised of a housing allowance awarded to Mr. Schrage of $1,050 and a $4,017 matching contribution under our 401(k) plan.

Option Grants in Last Fiscal Year

        The following table sets forth information regarding the granting of stock options to the named executive officers during 2005. The percentage of total options set forth below is based on an aggregate of 4,013,662.5 options granted to employees in 2005.

 
   
   
   
   
  Potential Realizable Value
at Assumed Annual Rates of
Share Price Appreciation
for Option Term(2)

 
  Number of
Securities
Underlying
Options Granted
(#)(1)

  Percent of
Total Options
Granted to
Employees In
Fiscal Year

  Individual Grants
Name

  Exercise
Price
($/Sh)

  Expiration
Date

  5%($)
  10%($)
Timothy Marquez                
William Schneider   1,144,237.5   28.0 % 6.00   March 1, 2015   $ 27,512,000   $ 43,839,000
    163,462.5   4.0 % 7.33   March 1, 2015     3,712,000     6,045,000
    163,462.5   4.0 % 8.67   March 1, 2015     3,494,000     5,827,000
David Christofferson   412,500   10.2 % 6.00   March 1, 2015     9,918,000     15,804,000
    67,500   1.7 % 7.33   March 1, 2015     1,533,000     2,496,000
    67,500   1.7 % 8.67   March 1, 2015     1,433,000     2,406,000
Terry Anderson   262,500   6.5 % 6.00   March 1, 2015     6,311,000     10,057,000
Gregory Schrage   225,000   5.6 % 6.00   March 1, 2015     5,410,000     8,620,000
    18,750   0.5 % 7.33   March 1, 2015     426,000     693,000
    18,750   0.5 % 8.67   March 1, 2015     401,000     668,000

(1)
The options vest over four years, with 20% of the options vested on the grant date and 20% of the options vesting on each subsequent anniversary of the grant date. See "—Stock Option Plans—2000 Stock Incentive Plan" for additional information concerning the terms of the options.

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(2)
The amounts shown reflect hypothetical gains that could be achieved for the options if exercised at the end of the option term. These amounts represent assumed rates of appreciation in the value of our common stock from the fair market value on the date of grant. Potential realizable values in the table above are calculated by:

Multiplying the number of shares of our common stock subject to the option by an assumed initial public offering price per share of $20.00.

Assuming that the aggregate stock value derived from that calculation compounds at the annual 5% or 10% rates shown in the table for the entire 10-year term of the option.

Subtracting from that result the total option exercise price.

        The 5% and 10% assumed rates of appreciation are suggested by the rules of the SEC and do not represent our estimate or projection of the future common stock price. Actual gains, if any, on stock option exercises will be dependent on the future performance of our common stock.

Fiscal Year-End Option Values

        The following table provides option exercise information for the named executive officers. No options were exercised during 2005. The table shows the number of exercisable and unexercisable options held at December 31, 2005. The "Value of Unexercised In-the-Money Options" shown in the table represents an amount equal to the difference between an assumed initial public offering price of $20.00 per share and the option exercise price, multiplied by the number of unexercised in-the-money options. These calculations do not take into account the effect of any taxes that may be applicable to the option exercises.

 
  Number of Securities
Underlying Unexercised
Options At Fiscal Year-End (#)

  Value of Unexercised
In-the-Money Options at
Fiscal Year-End ($)

Name

  Exercisable
  Unexercisable
  Exercisable
  Unexercisable
Timothy Marquez        
William Schneider   294,232.5   1,176,930.0   3,988,485   15,953,940
David Christofferson   109,500.0   438,000.0   1,479,000   5,916,000
Terry Anderson   52,500.0   210,000.0   735,000   2,940,000
Gregory Schrage   52,500.0   210,000.0   720,000   2,880,000

Employment Agreements

        During 2005, we entered into employment agreements with Timothy Marquez, William Schneider, David Christofferson, Greg Schrage, Terry Anderson and Mark DePuy, and nonqualified stock option agreements with each of those officers other than Mr. Marquez. In July 2005, we amended the agreements with Messrs. Schneider, Christofferson, Schrage, Anderson and DePuy.

        Each employment agreement provides that the officer will receive a specified base salary and will have a specified annual target bonus under an incentive compensation plan. Each agreement further provides that if a change of control of our company occurs and (i) the officer's employment is terminated (other than for specified types of misconduct) or (ii) he resigns for "good reason" (as that term is defined in the agreement), he will be entitled to a cash payment equal to three times his annual base salary and bonus and certain other benefits. Mr. Marquez's agreement also provides that he will be entitled to such payment and benefits if he resigns without good reason during the 30-day period that begins six months after a change of control occurs. If we terminate the officer's employment prior to the expiration of the term of the agreement (initially December 31, 2006), other than following a change of control and unless the termination results from misconduct by the officer, he will be entitled to a payment approximately equal to two times his annual base salary and bonus. Each employment

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agreement also provides that we will indemnify the officer in respect of certain claims brought against him in connection with his service with the company. The following table summarizes certain information relating to each of the employment agreements. In the case of Messrs. Schrage and Anderson, the amounts shown under "Base Salary" reflect salary increases that took effect on June 1, 2005. In the case of Mr. DePuy, the amounts shown reflect changes made in connection with his promotion to Senior Vice President and Chief Operating Officer in January 2006. We entered into substantially similar employment agreements with four additional officers in 2005 and the first quarter of 2006.

Officer

  Effective Date of Agreement
  Base Salary
  Target Bonus (% of base)
 
Timothy Marquez   March 1, 2005   $ 366,000   65 %
William Schneider   Feb. 5, 2005     285,000   65 %
Mark DePuy   Aug. 15, 2005     225,000   40 %
David Christofferson   March 1, 2005     216,000   40 %
Greg Schrage   March 1, 2005     194,260   25 %
Terry Anderson   March 1, 2005     216,320   25 %

        Pursuant to his employment agreement, Mr. DePuy received a signing bonus of $50,000 and receives a monthly mortgage assistance payment of $2,500. His monthly mortgage assistance payment will be increased to $3,500 when he relocates to the Santa Barbara/Ventura area.

        In addition, the employment agreements with Messrs. Schneider, Christofferson, Schrage, Anderson and DePuy (and, in each case, a contemporaneously executed nonqualified stock option agreement), provide for the grant of options to the relevant officer pursuant to our 2000 stock incentive plan. See "—Stock Option Plans."

Director Compensation

        From January to August 2005, we paid each of our non-employee directors a fee of $10,000 per quarter, plus a quarterly fee of $1,250 for each committee assignment and $1,000 for each board or committee meeting attended. In August 2005, we implemented a new fee structure pursuant to which we pay each of our non-employee directors an annual fee of $25,000, plus an annual fee of $10,000 for service on the audit committee, an annual fee of $5,000 for service on any other board committee and $1,000 for each board or committee meeting attended. In addition, in some circumstances committee members may be compensated for time directly spent on committee matters other than attendance at meetings, in amounts not to exceed $3,000 per quarter.

        In August 2005, we approved the grant of 45,000 options to each of our non-employee directors pursuant to our 2000 stock incentive plan and entered into a related nonqualified stock option agreement with each of those directors. The per share exercise price for each option was $10.67.

        In January 2006, we entered into a consulting agreement with Mr. O'Donnell. Pursuant to the agreement, Mr. O'Donnell provides up to 25 hours per month of consulting services to us through December 31, 2006 in consideration for a one-time consulting fee of $80,000.

Stock Option Plans

        We maintain two stock incentive plans, a 2000 stock incentive plan (the "2000 plan") and a 2005 stock incentive plan (the "2005 plan"). To date, we have granted options to purchase a total of 4,253,662.5 shares of our common stock under the plans, approximately 39% of which are currently vested. The options have a weighted average exercise price of $7.58 per share. No additional awards will be made under the 2000 plan. Currently, 1,460,000 shares of common stock are available for issuance under the 2005 plan. Promptly following the completion of this offering, we expect to grant options to purchase up to an additional 500,000 shares of common stock to our non-executive officer employees under the 2005 stock incentive plan. The exercise price of these options will be the offering

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price. Twenty percent of the options will vest upon grant, and an additional 20% will vest on each of the first four anniversaries of the grant date.

        The following table sets forth certain information with respect to all currently outstanding options granted under the 2000 plan and the 2005 plan. No options granted under either plan have been exercised.

Officer/Director

  Date of Award
  Options Granted
  Exercise Price
 
William Schneider   March 1, 2005   1,144,237.5   $ 6.00  
        163,462.5     7.33  
        163,462.5     8.67  
David Christofferson   March 1, 2005   412,500.0     6.00  
        67,500.0     7.33  
        67,500.0     8.67  
Greg Schrage   March 1, 2005   225,000.0     6.00  
        18,750.0     7.33  
        18,750.0     8.67  
Roger Hamson   March 1, 2005   225,000.0     6.00  
        18,750.0     7.33  
        18,750.0     8.67  
Terry Anderson   March 1, 2005   262,500.0     6.00  
Mark DePuy   Aug. 15, 2005   93,750.0     12.00  
        93,750.0     13.33  
    Jan. 23, 2006   100,000.0     20.00  
J. Timothy Brittan   Aug. 26, 2005   45,000.0     10.67  
J.C. "Mac" McFarland   Aug. 26, 2005   45,000.0     10.67  
Ed O'Donnell   Aug. 26, 2005   45,000.0     10.67  
Eloy Ortega   Aug. 26, 2005   45,000.0     10.67  
Joel Reed   Aug. 26, 2005   45,000.0     10.67  
Glen C. Warren, Jr.   Aug. 26, 2005   45,000.0     10.67  
Others       890,000.0     7.96 (1)
       
 
 
Total       4,253,662.5     7.58 (1)(2)

(1)
Represents the weighted average exercise price.

(2)
As described above, we expect to grant options to purchase up to an additional 500,000 shares of common stock promptly following the completion of this offering.

2000 Stock Incentive Plan

        The 2000 plan provides for grants of nonqualified stock options and restricted stock to our employees, officers, directors and consultants. Pursuant to the terms of the 2000 plan, either the board of directors or a designated board committee may administer the plan, including by determining which eligible participants will receive awards, when awards will be granted, the terms of awards and the number of shares that will be subject to awards. The 2000 plan is administered by our board of directors. The board has limited the number of shares of common stock that may be made subject to options awarded under the 2000 plan to the number of shares underlying the options that are currently outstanding. As a result, we do not expect to make any additional awards under the 2000 plan. Unless terminated sooner by our board of directors, the 2000 plan will terminate on the tenth anniversary of the date it was adopted.

        Options granted pursuant to the 2000 plan expire ten years after the date of grant. The 2000 plan provides that the exercise price of options must generally be at least 85% of the fair market value of the underlying common stock on the date of grant. The exercise prices of all options granted under the plan were equal to or greater than the fair market value of the underlying stock on the date of grant as determined by the company, taking into account minority and other discounts we deemed appropriate.

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The 2000 plan provides that the number of shares purchasable upon exercise of an option, and the exercise price, will be adjusted to reflect the terms of any reclassification, stock split, merger or similar transaction.

        All awards under the 2000 plan have been granted pursuant to substantially similar nonqualified stock option agreements. Pursuant to the plan and the agreements, options vest over four years, with 20% of the options vested on the grant date and 20% of the options vesting on each subsequent anniversary of the grant date. The plan and the agreements provide that all options will become immediately vested following a change of control of our company. The agreements with employee option holders provide that all the holder's options will become immediately vested if we terminate the holder's employment, unless the termination is for specified types of misconduct. The agreements with director option holders provide that any unvested options will terminate when the director's service to the company ceases.

        In June and July 2006, we amended our nonqualified stock option agreements with each person granted options under the 2000 plan. The amendment changes the definition of "change in control" for the purposes of the agreement such that a change in control in our company will be deemed to occur if (i) any person or group other than Timothy Marquez (or a member of his family) becomes a beneficial owner of more than 50% of our voting stock, (ii) our stockholders approve a merger involving us (unless the merger meets certain specified criteria), (iii) our stockholders approve a plan to liquidate our company or to sell all or substantially all of our assets or (iv) Timothy Marquez (together with members of his family) is no longer the largest beneficial owner of our voting securities and Mr. Marquez is no longer our CEO or Chairman. We also entered into a bonus payment agreement with each option holder pursuant to which, when we pay a dividend on our common stock, the holder will be entitled to receive a payment equal to the dividend that would have been paid on the shares of common stock underlying his options had those options been exercised as of the record date relating to the dividend. The agreement specifies that such payment will be made whether the dividend in question is in the form of cash or property.

        Each nonqualified stock option agreement contains provisions (i) limiting the transferability of shares of common stock acquired upon the exercise of options, (ii) giving us a right of first refusal if any of those shares are proposed to be transferred, (iii) allowing the holder of those shares to cause us to repurchase them for fair market value in certain circumstances, (iv) giving holders "tag-along" rights with respect to those shares in the event of certain sales of stock by Timothy Marquez or his affiliates and (v) giving Mr. Marquez and his affiliates "drag-along" rights with respect to those shares in connection with such sales. The 2000 plan also contains a provision that allows us to repurchase shares of common stock acquired upon the exercise of options for their fair market value in certain circumstances. Each of the provisions described in this paragraph will terminate on the date our common stock is registered under the Exchange Act and listed on a national securities exchange.

        As discussed above, we believe that the exercise prices of all options granted under the 2000 plan were equal to or greater than the fair market value of the underlying stock on the date of grant. If it were subsequently determined that the exercise prices of some or all of the options were less than fair market value, we could be required to record a compensation expense reflecting the difference between the exercise price and fair market value. If the difference were determined to be significant with respect to some or all of the options, the adverse impact of the resulting compensation charge on our net income for the year ended December 31, 2005 could be material.

2005 Stock Incentive Plan

        The 2005 plan provides for the grant of incentive stock options, nonqualified stock options, restricted stock and stock appreciation rights to our employees, officers, directors and consultants. Pursuant to the terms of the 2005 plan, either the board of directors or a board committee is authorized to administer the plan, including by determining which eligible participants will receive

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awards, when awards will be granted and the terms and amounts of awards. The 2005 plan is administered by our compensation committee. The 2005 plan was amended and restated in May 2006. As amended and restated, the 2005 plan provides for the issuance of up to 1.7 million shares of common stock pursuant to awards under the plan. Unless terminated sooner by our board of directors, the 2005 plan will terminate on the tenth anniversary of the date of the adoption of the amended and restated plan. No awards were granted under the plan in 2005. To date in 2006, we have granted options to purchase a total of 240,000 shares of common stock to three of our officers under the plan. Those options have a weighted average exercise price of $16.58. Promptly following the completion of this offering, we expect to grant options to purchase up to an additional 500,000 shares of common stock to our non-executive officer employees. The exercise price of these options will be the offering price.

        Each award under the 2005 plan has been or will be made pursuant to an award agreement that specifies the terms of the award, including the vesting schedule, if any. We expect that options granted under the 2005 plan will generally vest over a four year period, with 20% of the options vested on the date of grant and 20% of the options vesting on each subsequent anniversary of the grant date. The compensation committee will have the authority to accelerate any vesting requirements or time-based limitations on exercisability of options or other awards. Stock options granted pursuant to the 2005 plan will generally expire ten years after the date of grant. The exercise price of incentive stock options will generally be at least equal to the fair market value of the underlying common stock on the date of grant. The exercise price of nonqualified stock options will generally be at least equal to 85% of the fair market value of the underlying common stock on the date of grant, except that the exercise price of nonqualified stock options granted to our CEO and our four other most highly compensated officers will generally be at least equal to the fair market value of the underlying common stock. If a holder of options granted under the plan terminates his employment with or service to our company, his options will, subject to certain exceptions, automatically expire. If we terminate the option holder's employment with or service to us without cause, the holder may generally exercise any vested options for a period of 180 days following the termination.

        In the event of a change of control of our company, our compensation committee will generally accelerate the exercisability of all options granted under the 2005 plan such that they may be exercised in full upon or immediately prior to the completion of the transaction or event that results in the change of control, although the committee will have the discretion to take certain different or additional actions in those circumstances, including by arranging for cash settlement of stock awards granted under the plan. For purposes of the plan, a "change of control" will be deemed to occur if (i) any person or group other than Timothy Marquez (or a member of his family) becomes a beneficial owner of more than 50% of our voting stock, (ii) our stockholders approve a merger involving us (unless the merger meets certain specified criteria), (iii) our stockholders approve a plan to liquidate our company or sell all or substantially all of our assets or (iv) Timothy Marquez (together with members of his family) is no longer the largest beneficial owner of our voting securities and Mr. Marquez is no longer our CEO or Chairman. The 2005 plan further provides that the number of shares purchasable upon exercise of an option granted under the plan, and the exercise price, will be adjusted to reflect the terms of any reclassification, stock split or similar transaction.

        The board of directors or the compensation committee may amend the 2005 plan at any time, subject to shareholder approval requirements imposed by the Internal Revenue Code, Rule 16b-3 under the Exchange Act and applicable stock exchange or Nasdaq rules.

Indemnification

        We maintain directors' and officers' liability insurance. Our certificate of incorporation includes provisions limiting the liability of directors and officers and indemnifying them under certain circumstances. We have also entered into indemnification agreements with each of our directors providing the directors with additional assurances in a manner consistent with Delaware law. As noted in "—Executive Compensation—Employment Agreements," we have employment agreements with certain of our officers that also provide for indemnification in some circumstances.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Ownership and Related Disputes and Transactions

Background

        From mid-2002 until June 2004, our ownership structure and management was affected by a number of related disputes among Timothy Marquez, a business associate of Mr. Marquez's who co-founded our company with Mr. Marquez, our former CFO, and certain affiliates of Enron that formerly held our preferred stock. Our company was founded in 1992 by Messrs. Marquez and his business associate. Prior to 1998, when two affiliates of Enron made a $60 million equity investment in our company, Mr. Marquez, his business associate and the former CFO were our principal stockholders.

Dispute with Enron Affiliates and Change in Management

        In 2001, following failed negotiations concerning the Enron affiliates' request that we repurchase their equity interest, a dispute arose between the company's management and the Enron affiliates concerning the qualifications of certain individuals nominated by the Enron affiliates to become members of our board of directors. In March 2002, in connection with this dispute, Mr. Marquez's business associate, the former CFO and the Enron affiliates gained control of the board of directors. In June 2002, the board of directors terminated the employment of Mr. Marquez, who had been CEO since the company's formation, and replaced him with his business associate.

Filing of Marquez Actions

        After being terminated, Mr. Marquez filed a suit against the company in the Santa Barbara, California Superior Court, asserting that he had been wrongfully terminated and that the company had breached his employment agreement. The company incurred a $6.0 million charge against its 2003 earnings with respect to the settlement of this action. The company filed a cross-claim in the action to recover from Mr. Marquez the principal and accrued interest claimed due under a written promissory note dated December 11, 2000, which represented indebtedness of approximately $1.4 million. Mr. Marquez also filed a stockholders' derivative action in the U.S. District Court for the Central District of California based on his claim that his business associate, the former CFO and certain other directors had breached their fiduciary duties by approving the payment of cash dividends on the preferred stock held by the Enron affiliates.

Settlement of Marquez Actions and Willows and Grimes Transactions

        In February 2004, before either the employment action or the derivative action went to trial, the parties agreed to settle both actions. The settlement agreement relating to the derivative action provided for a dismissal of the action without payment of funds by the company or the defendants. Court approval of the settlement of the derivative action was obtained in December 2004.

        With respect to the employment action, Mr. Marquez, the company and the Enron-nominated directors entered into a settlement agreement that provided for a payment of $300,000 to Mr. Marquez in exchange for a mutual release and dismissal of the action. That payment was made in March 2004 and the action was dismissed with prejudice. Pursuant to a separate agreement, Mr. Marquez provided to the company a new promissory note dated February 1, 2004, in the principal amount of approximately $1.4 million, and the company cancelled and returned the original note.

        In connection with the aforementioned settlement, the company also agreed to sell its Willows and Grimes fields to Marquez Energy, a company controlled by Mr. Marquez, for approximately $13.8 million. The agreement governing that transaction, which we refer to as the sale agreement, provided that the sale, when completed, would have retroactive effect from February 1, 2004. Both the company and Marquez Energy believed the fair market value of the properties to be higher than the contemplated sale price; the difference between the sale price and the actual value of the properties was intended to be partial compensation to Mr. Marquez for agreeing to the dismissal of the employment action. The sale agreement also provided that the company would pay legal fees incurred

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by Marquez Energy and Mr. Marquez in connection with the transaction. In this regard, the company made a payment of $700,000 to counsel for Mr. Marquez in March 2004. In the sale agreement, the company's obligation to sell the properties was made subject to the condition that it obtain a new credit facility. In the event this condition was not satisfied or waived by May 24, 2004, the company would be obliged to pay Marquez Energy a termination fee, subject to offset in the amount of the new Marquez promissory note (to the extent not then repaid). The agreement further provided that even after Marquez Energy's receipt of the termination fee, it would have the option of extending the effectiveness of the agreement until August 20, 2004 by depositing $1,500,000 in escrow.

        The company did not obtain a new credit facility during the requisite period and the sale of the Willows and Grimes fields did not occur. Accordingly, on May 25, 2004, the company paid Marquez Energy a termination fee of $4.5 million, of which $3.1 million was paid in cash and $1.4 million in the form of the issuance to Marquez Energy of a note in that amount by Mr. Marquez and the related cancellation of Mr. Marquez's note to the company. Discussions ensued concerning Marquez Energy's exercise of its option to extend the effectiveness of the agreement. As a result of these discussions, on August 17, 2004, the company and Marquez Energy entered into a memorandum of settlement pursuant to which Marquez Energy relinquished all of its rights to acquire the Willows and Grimes properties in return for a cash payment of $500,000 plus the right to participate in the development of future reserves, other than currently identified proved reserves, in the Willows and Grimes fields. This agreement was formalized in a participation rights agreement executed in September 2004. Because of negotiations concerning the company's prospective acquisition of Marquez Energy, the parties agreed to suspend the effectiveness of the agreement pending the outcome of those negotiations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—Acquisitions and Divestitures—Acquisition of Marquez Energy." No value was assigned to the agreement in determining the price the company paid to acquire Marquez Energy.

Sale of Stock from Mr. Marquez's Business Associate and the Former CFO to Marquez

        In May 2004, Mr. Marquez's business associate and the former CFO, together with certain of their respective affiliates, agreed to sell all of their stock in the company to Mr. Marquez. The sales occurred in a transaction that closed in July 2004. Mr. Marquez returned as our CEO in June 2004. Following the transaction, Mr. Marquez owned approximately 94% of our outstanding common stock.

Repurchase of Preferred Stock from Enron Affiliates

        On November 4, 2004, the company purchased the preferred stock held by the Enron affiliates (which constituted all of our outstanding preferred stock) for $72.0 million. At the closing of the transaction, the company and certain of its affiliates (including Mr. Marquez and Marquez Energy), executed a mutual release with the Enron affiliates and certain of their affiliates (collectively referred to as the Enron parties). Pursuant to the release, the company and its affiliates released the Enron parties from any claims by the company or its affiliates based on facts arising at or prior to the closing and the Enron parties released the company and its affiliates from any such claims by them. Claims that may arise under the sale and purchase agreement governing the transaction are not covered by the release.

Merger with Marquez Trust

        On December 22, 2004, the company merged with a corporation the sole stockholder of which was the Marquez Trust, a trust controlled by our CEO, Timothy Marquez, and his wife. In the merger, the company paid an aggregate of $5.4 million in cash for 2,212,208 shares of our common stock. The merger resulted in an increase in Mr. Marquez's beneficial ownership of our common stock from 94% to 100%.

Real Property Dividends and Related Transactions

        In 2006, we have paid dividends on our common stock consisting of (i) a 51-acre parcel of real property located in Carpinteria (referred to as the bluffs property), (ii) an option to acquire an

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additional interest in land associated with the bluffs property if, as a result of current negotiations, we acquire that interest and (iii) 100% of the membership interests in our wholly-owned subsidiary 6267 Carpinteria Avenue, LLC. As described below, we have entered into certain agreements with the Marquez Trust in connection with these dividends. We believe that the terms of these ancillary agreements are as favorable to us as could have been obtained through arms' length negotiations with an unaffiliated party. We will pay to each holder of outstanding options granted under our 2000 stock incentive plan a bonus with respect to those dividends. The amount of the bonus will be equal to the amount the option holders would have received if we had paid a cash dividend of equal value and the options held by such holders had been exercised, or approximately $1.2 million in the aggregate. Approximately $0.6 million of that amount has been paid to date.

The Bluffs Property

        The bluffs property is located on the coast in Carpinteria, California. The property consists of a 100% interest we hold in 46 acres and a 50% interest we hold in an adjacent ten acres that is used primarily for parking (the parking area). The current zoning status of the property is "industrial coastal dependent." We conduct some minor processing activities on the property. Our facilities are currently spread over approximately 15 acres of the property. We estimate that the current value of the property is approximately $5.0 million.

        In August 2006, in connection with the contemplated dividends, we entered into a dividend distribution agreement with the Marquez Trust and an affiliate of the trust, and a ground lease and development agreement with the affiliate. Under the ground lease, which has a 20-year term, we will lease the bluffs property for $1.00 per year. The development agreement provides that an affiliate of the trust will have the right to cause us to consolidate our operations on the property such that the operations will occupy no more than two acres. If the affiliate exercises this right, we will have two years to obtain the governmental consents necessary to effect the consolidation, and one year from the date of our receipt of those consents to complete the consolidation. The option may be exercised at any time within sixty days of the second anniversary of the date of the agreement (the first option period), within sixty days of the third anniversary of that date (the second option period), and at any time after the fourth anniversary of that date (the third option period). If the option is exercised in the first option period, the affiliate will pay us a fee of $3.0 million when the consolidation is completed. If the option is exercised in the second option period, the affiliate will pay us a fee of $2.0 million when the consolidation is completed. No fee will be payable if the option is exercised in the third option period. Following consolidation, we will have the right to occupy the two acre site for $1.00 per year for as long as we conduct oil and natural gas operations there. We do not believe that the consolidation will have an adverse effect on our operations. However, we currently estimate that the cost of effecting the consolidation would be approximately $10 million. We will be required to pay property taxes on the entire property until the consolidation is completed, at which time we would become responsible only for taxes relating to the two acre site. At the time of the consolidation, we would be required to obtain a release of the lien on the property referred to above. We could obtain the release by increasing our abandonment bond relating to the property by $8.5 million. It is possible that permitting issues may preclude us from timely consolidating to the two acre site, if and when we are requested to do so. In such event, we will be required to pay rent at a market rate (based on current zoning) for space we occupy in excess of the two acres. It is possible that development of the property adjacent to the two acre site may affect our operations resulting in costs and constraints that we do not currently experience.

The Parking Area

        We are currently in negotiations to acquire the 50% interest in the parking area that we do not already own. Pursuant to the dividend distribution agreement, if we acquire that interest, the Marquez Trust will have a three-year option to acquire the interest for the price we pay for it plus interest. We expect the purchase price for the interest to be approximately $250,000. Following exercise of the option, we would retain the right to use a portion of the parking area for our operations and for third parties who use the pier located on the property for so long as the pier remains in existence.

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Office Building Dividend

        The principal asset of 6267 Carpinteria Avenue, LLC is the office building we lease in Carpinteria, California. 6267 Carpinteria Avenue, LLC acquired the office building in December 2004 for $14.2 million. It financed a portion of the purchase with a $10.0 million loan secured by a lien on the office building. The loan is non-recourse to us and we are not responsible for repayment of the loan. In connection with the purchase of the building, we agreed to indemnify the lender against certain liabilities principally relating to environmental matters and certain violations of the applicable loan documents. Pursuant to an indemnity and guaranty agreement entered into in connection with the dividend, the Marquez Trust has agreed to indemnify us against certain costs we may incur with respect to those indemnification obligations. We paid a fee of $100,000 to obtain the lender's consent to the dividend. We estimate that the value of the office building, net of the amount outstanding on the loan, was approximately $4.9 million at the time the dividend was paid.

        We and 6267 Carpinteria Avenue, LLC are parties to a lease pursuant to which we lease the office building from 6267 Carpinteria Avenue, LLC for $1.1 million per year. The payment of the dividend had no effect on our rights and obligations as set forth in the lease. The lease, which was entered into in 2001 and was amended in 2004, provides that the annual rent will increase by 10% in 2009 and by an additional 10% in 2014. We are also responsible for reimbursing 6267 Carpinteria Avenue, LLC for certain building operating expenses. The lease will expire in 2019.

Other Related Party Transactions

        William Schneider, our President, was a managing director at BMO Capital Markets (formerly known as Harris Nesbitt) prior to joining our company. During the period of Mr. Schneider's employment with BMO Capital Markets, that firm provided certain investment banking services to us as described in "Underwriting."

        In November 1999, while Ed O'Donnell was an officer of our company, we loaned him $100,000 to assist him in financing the purchase of a home. The rate of interest on the loan was 6% per annum. We forgave the principal and accrued interest on the loan in January 2003. As described in "Management—Directors and Executive Officers," Mr. O'Donnell is currently one of our directors and provides consulting services to us on a part-time basis.

        See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—Acquisitions and Divestitures—Acquisition of Marquez Energy" and "Shares Eligible for Future Sale—Registration Rights Agreement."

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PRINCIPAL AND SELLING STOCKHOLDERS
AND BENEFICIAL OWNERSHIP OF MANAGEMENT

        The following table sets forth information as of September 30, 2006 regarding ownership of our common stock by the selling stockholders, our directors, our executive officers and our directors and executive officers as a group. Prior to the completion of this offering, the selling stockholders are the only record holders of our common stock. The selling stockholders are:

    the Marquez Trust, the trustees of which are Timothy Marquez, our Chairman and CEO, and his wife Bernadette Marquez; and

    the Denver Foundation, a community charitable foundation to which the Marquez Trust donated 2,500,000 shares of our common stock on August 18, 2006. Timothy and Bernadette Marquez advise the Denver Foundation with respect to certain matters regarding the use of funds held by the Denver Foundation, but do not beneficially own the shares of our common stock held by the foundation.

        Beneficial ownership has been determined in accordance with applicable SEC rules, pursuant to which a person is deemed to be the beneficial owner of securities if he or she has or shares voting power or investment power with respect to such securities or has the right to acquire beneficial ownership within 60 days. Unless otherwise indicated, to our knowledge, the persons listed in the following table have sole voting and investment power with respect to the shares indicated. The address of our directors and executive officers is 370 17th Street, Suite 2950, Denver, Colorado 80202-1370. The percentages shown below are based on 32,692,500 shares of common stock issued and outstanding as of September 30, 2006. The amount shown for each selling stockholder reflects shares owned of record and the amount shown for each executive officer and each director, in each case other than Timothy

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Marquez, reflects shares issuable upon the exercise of currently vested options. Beneficial ownership representing less than one percent is denoted with an asterisk.

 
  Beneficial Ownership
Prior to Offering

   
  Beneficial Ownership
After Offering

 
Name of Beneficial Owner

  Shares Being
Offered

 
  Shares
  Percent
  Shares
  Percent
 
Selling Stockholders                      
Marquez Trust(1)   27,692,500   84.7 % 1,250,000   26,442,500   61.9 %
The Denver Foundation(2)   2,500,000   7.6 % 1,250,000   1,250,000   2.9 %
Executive Officers                      
Timothy Marquez   30,192,500   92.4 % 0 (3) 28,942,500   67.8 %
William Schneider   588,465   1.8 % 0   588,465   1.4 %
David Christofferson   219,000   *   0   219,000   *  
Mark DePuy   95,000   *   0   95,000   *  
Terry Anderson   105,000   *   0   105,000   *  
Douglas Griggs   8,000   *   0   8,000   *  
Non-Employee Directors                      
J. Timothy Brittan   18,000   *   0   18,000   *  
J.C. "Mac" McFarland   18,000   *   0   18,000   *  
Ed O'Donnell   18,000   *   0   18,000   *  
Eloy Ortega   18,000   *   0   18,000   *  
Joel Reed   18,000   *   0   18,000   *  
Glen Warren   18,000   *   0   18,000   *  
All directors and executive officers as a group   31,315,965   92.6 % 0 (3) 30,065,965   68.6 %

(1)
If the underwriters exercise in full their right to purchase additional shares, the Marquez Trust will own 26,255,000 shares following the offering, or 59.4% of the total.

(2)
If the underwriters exercise in full their right to purchase additional shares, the Denver Foundation will own 1,062,500 shares following the offering, or 2.4% of the total.

(3)
Mr. Marquez is not offering any shares in his individual capacity. As described above, however, he is a trustee of the Marquez Trust, which is offering shares. Mr. Marquez's beneficial ownership following the offering will be reduced to the extent of sales by the Marquez Trust. The amounts shown for Mr. Marquez also include 2,500,000 shares of common stock held by the Marquez Foundation, a private charitable foundation established by Mr. Marquez and his wife. The Marquez Foundation is not offering shares in this offering.

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DESCRIPTION OF CAPITAL STOCK

        Our authorized capital stock consists of:

    200 million shares of common stock, par value $.01 per share, of which 42,692,500 shares will be issued and outstanding following the completion of this offering; and

    20 million shares of preferred stock, par value $.01 per share, of which no shares will be issued and outstanding following the completion of this offering.

        The rights of our stockholders will be governed by Delaware law, our amended and restated certificate of incorporation and our bylaws. The following is a summary of the material terms of our capital stock. For additional information regarding our capital stock, please refer to the applicable provisions of Delaware law, our certificate of incorporation and our bylaws.

Common Stock

Dividend and Liquidation Rights

        Holders of our common stock may receive dividends when, as and if declared by our board of directors out of funds legally available for the payment of dividends. As a Delaware corporation, we may pay dividends out of surplus or, if there is no surplus, out of net profits for the fiscal year in which a dividend is declared and/or the preceding fiscal year. Section 170 of the Delaware General Corporation Law (the "DGCL") also provides that dividends may not be paid out of net profits if, after the payment of the dividend, capital is less than the capital represented by the outstanding stock of all classes having a preference upon the distribution of assets.

        Our debt agreements restrict our ability to pay dividends on our common stock. In addition, when we pay dividends on our common stock, we are obligated to make a bonus payment to each holder of stock options granted under our 2000 stock incentive plan in an amount equal to the dividend that would have been paid on the shares of common stock underlying the holder's options had those options been exercised as of the record date relating to the dividend. See "Management—Stock Option Plans—2000 Stock Incentive Plan."

        In the event of our liquidation, holders of common stock will be entitled to share ratably in the net assets legally available for distribution to stockholders after the payment of all of our debts and other liabilities.

        The right of holders of our common stock to receive dividends and distributions upon liquidation will be subject to the satisfaction of any applicable preference granted to the holders of any preferred stock that may then be outstanding.

Voting and Other Rights

        Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. The holders of common stock do not have cumulative voting rights in the election of directors. The affirmative vote of at least 662/3% of our outstanding voting stock will be required to amend or repeal provisions of our certificate of incorporation relating to the number and classification of our directors, indemnification of officers and directors and certain other matters.

No Preemptive, Conversion or Redemption Rights

        The common stock has no preemptive, conversion or exchange rights and is not subject to further calls or assessment by us. There are no redemption, retraction, purchase for cancellation or sinking fund provisions applicable to the common stock.

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Preferred Stock

        Our amended and restated certificate of incorporation authorizes our board of directors to establish one or more series of preferred stock. With respect to any series of preferred stock, our board of directors is authorized to determine the terms and rights of that series, including:

    The designation of the series and the number of shares to constitute the series;

    The dividend rate of the series, the conditions and dates upon which such dividends will be payable, the relation which such dividends will bear to the dividends payable on any other class or classes of stock, and whether such dividends will be cumulative or noncumulative;

    Whether the shares of the series will be subject to redemption by us and, if made subject to such redemption, the times, prices and other terms and conditions of such redemption;

    The terms and amount of any sinking fund provided for the purchase or redemption of the shares of the series;

    Whether or not the shares of the series will be convertible into or exchangeable for shares of any other class or classes of stock, and, if provision is made for conversion or exchange, the times, prices, rates, adjustments and other terms and conditions of such conversion or exchange;

    The extent, if any, to which the holders of shares of the series will be entitled to vote with respect to the election of directors or otherwise;

    The restrictions, if any, on the issue or reissue of any additional shares of preferred stock of that series; and

    The rights of the holders of the shares of the series upon the dissolution, liquidation, or winding up of the corporation.

        Except as otherwise required by law or by any stock exchange, the authorized shares of preferred stock and common stock will be available for issuance without further action by you.

        Although we have no intention at the present time of doing so, in the future we could issue a series of preferred stock that could impede the completion of a merger, tender offer or other takeover attempt. We will make any determination to issue preferred stock based on our judgment as to the best interests of our company and our stockholders. In so acting, we could issue preferred stock having terms that could discourage an acquisition attempt or other transaction that some, or a majority, of our stockholders might believe to be in their best interests or in which stockholders might receive a premium for their common stock over the then-current market price of the common stock.

Authorized but Unissued Capital Stock

        Delaware law does not require stockholder approval for any issuance of authorized shares. However, the listing requirements of certain stock exchanges generally require stockholder approval of certain issuances equal to or exceeding 20% of the then-outstanding voting power or then-outstanding number of shares of common stock. These additional shares may be used for a variety of corporate purposes, including future offerings, to raise additional capital or to facilitate acquisitions.

        One of the effects of the existence of unissued and unreserved common stock and preferred stock may be to enable our board of directors to issue shares to persons friendly to current management, which issuance could render more difficult or discourage an attempt to obtain control of our company by means of a merger, tender offer, proxy contest or otherwise, and thereby protect the continuity of our management and possibly deprive the stockholders of opportunities to sell their shares of common stock at a premium to prevailing market prices.

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Certain Anti-Takeover Effects of Provisions of Our Certificate of Incorporation and Bylaws

        Our certificate of incorporation and bylaws also contain provisions that we describe in the following paragraphs, which may delay, defer, discourage or prevent a change in control of our company, the removal of our existing management or directors, or an offer by a potential acquirer to our stockholders, including an offer by a potential acquirer at a price higher than the market price for the stockholders' shares.

Special Stockholders' Meetings

        Our certificate of incorporation provides that special meetings of the stockholders may be called only by the chairman of the board, the CEO or, upon the written request of a majority of the board of directors, any of our officers.

Classified Board of Directors

        Our certificate of incorporation provides that our board of directors is to be divided into three classes, designated as Class I, Class II and Class III. At each annual meeting of stockholders, successors to the directors whose terms expired at that annual meeting will be elected for a three-year term.

Board Vacancies to be Filled by Remaining Directors and Not Stockholders

        Our certificate of incorporation provides that any vacancies on our board will be filled by the affirmative vote of the majority of the remaining directors, even if such directors constitute less than a quorum. No such vacancy will be filled by our stockholders.

Requirements for Advance Notification of Stockholder Proposals and Director Nominations

        Our bylaws establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors or a committee of the board of directors. These provisions may preclude stockholders from bringing matters before a stockholders' meeting or from making nominations for directors at a stockholders' meeting.

Action by Written Consent

        Under our certificate of incorporation, stockholders may take action by written consent only if the action is first approved by our board of directors.

No Cumulative Voting

        Our certificate of incorporation and bylaws do not provide for cumulative voting in the election of directors.

Delaware Anti-Takeover Law

        Our company is a Delaware corporation subject to the provisions of Section 203 of the DGCL, an anti-takeover law. Generally, this statute prohibits a publicly-held Delaware corporation from engaging in a business combination with an "interested stockholder" for a period of three years after the date of the transaction in which such person became an interested stockholder, unless:

    prior to such date, the board of directors of the corporation approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;

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    upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the voting stock outstanding those shares owned (i) by persons who are directors and also officers and (ii) by employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to this plan will be tendered in a tender or exchange offer; or

    on or subsequent to such date, the business combination is approved by the board of directors and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 662/3% of the outstanding voting stock that is not owned by the interested stockholder.

        A "business combination" includes a merger, consolidation, asset sale or other transaction resulting in a financial benefit to the stockholder. For purposes of Section 203, an "interested stockholder" is defined to include any person that is:

    the owner of 15% or more of the outstanding voting stock of a corporation;

    an affiliate or associate of a corporation and was the owner of 15% or more of the outstanding voting stock of the corporation at any time within three years immediately prior to the date on which it is sought to be determined whether such person is an interested stockholder; and

    an affiliate or associate of the persons described above.

        We anticipate that the provisions of Section 203 may encourage parties interested in acquiring us to negotiate in advance with our board because the 662/3% stockholder approval requirement would be avoided if a majority of the directors then in office approve either the business combination or the transaction that results in the stockholder becoming an interested stockholder. None of Mr. Marquez, his wife or the Marquez Trust will be deemed an interested stockholder for the purposes of Section 203.

Transfer Agent and Registrar

        The transfer agent and registrar for our common stock will be Computershare Trust Company, Inc.

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SHARES ELIGIBLE FOR FUTURE SALE

General

        Prior to this offering, there has been no public trading market for our common stock. Sales of substantial amounts of common stock in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices and could impair our ability to raise capital in the future through the sale of our equity securities.

        Upon completion of the offering, 42,692,500 shares of our common stock will be outstanding. All of the 12,500,000 shares sold in the offering, together with any shares sold upon exercise of the underwriters' option to purchase additional shares, will be freely tradable without restriction by persons other than our "affiliates," as that term is defined under Rule 144 under the Securities Act of 1933. Persons who may be deemed to be affiliates generally include individuals or entities that control, are controlled by or are under common control with us and may include our executive officers, directors and significant stockholders. The remaining shares of common stock will constitute "restricted securities" within the meaning of Rule 144 and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration. In addition, sales of these shares, and shares purchased by participants in the directed share program, will be subject to the restrictions on transfer contained in the lock-up agreements described below.

Rule 144

        In general, under Rule 144 as currently in effect, a person who has beneficially owned restricted shares for at least one year, including the holding period of any prior owner (other than an affiliate of ours) would be entitled to sell within any three-month period a number of shares that does not exceed the greater of:

    1% of the number of shares of common stock then outstanding; or

    the average weekly reported trading volume of the common stock during the four calendar weeks preceding the filing of a Form 144 with respect to the sale.

        Sales under Rule 144 also are subject to manner of sale provisions, notice requirements and to the availability of current public information about us. Under Rule 144(k), a person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner (other than an affiliate of ours), is entitled to sell those shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144. The holding period requirement will be satisfied for each of the selling stockholders.

Registration Rights Agreement

        We entered into a registration rights agreement with the Marquez Trust in August 2006. Pursuant to that agreement, the trust will have the right to demand that we register for resale some or all of its shares under the Securities Act, and will have the right to include some or all of its shares in registration statements we file, in each case subject to certain customary conditions, including the right of the underwriters to limit the number of shares included in any offering by us that is underwritten. The trust will have the right to cause us to effect up to three registrations on Form S-1 and an unlimited number of registrations on Form S-3. We will not, however, be required to effect more than two demand registrations in any 12-month period, and we will not be required to file a registration statement within 180 days of the completion of any underwritten offering of our securities. We will pay certain expenses in connection with any registration effected pursuant to the agreement, but the trust will pay the underwriting commissions and fees associated with the sale of its shares in any

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underwritten offering. The trust will not be entitled to exercise its rights under the registration rights agreement prior to the expiration of the lock-up period described below.

Lock-Up Agreements

        We, the selling stockholders, certain of our officers and each of our directors have agreed that, without the prior consent of each of Credit Suisse Securities (USA) LLC, Lehman Brothers Inc. and J.P. Morgan Securities Inc., we will not directly or indirectly offer, pledge, sell, hedge or otherwise dispose of any shares of our common stock or any securities convertible into or exchangeable or exercisable for our common stock for a period of 180 days after the date of this prospectus (a period that may be extended by up to 34 days in certain circumstances). Participants in our directed share program will be subject to substantially similar lock-up agreements. See "Underwriting."

Stock Options

        We intend to file a registration statement on Form S-8 under the Securities Act covering all of the shares of common stock underlying options granted, or to be granted, under our stock plans. We expect to file this registration statement promptly following the completion of this offering. Upon exercise of the options, shares registered under the Form S-8 registration statement will, subject to Rule 144 limitations applicable to affiliates, be available for sale in the open market, except to the extent that the shares are subject to the lock-up agreements described above.

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DESCRIPTION OF INDEBTEDNESS

Revolving Credit Facility

        We entered into an amendment and restatement of our revolving credit facility on March 30, 2006 as part of the TexCal transaction. The revolving credit facility was further amended on May 2, 2006 and October 25, 2006. The revolving credit facility was provided by the Bank of Montreal, as administrative agent, Harris Nesbitt Corp., as lead arranger, Credit Suisse Securities (USA) LLC and Lehman Brothers Inc., as co-arrangers, and Credit Suisse, Cayman Islands Branch, and Lehman Commercial Paper Inc., as co-syndication agents. We borrowed $119.5 million under the revolving credit facility on March 31, 2006 to finance part of the purchase price for TexCal. The revolving credit facility provides for borrowings of up to $300.0 million, with a current borrowing base of $230.0 million. The revolving credit facility is secured by a first priority lien on substantially all of our oil and natural gas properties and other assets, including the stock of all of our subsidiaries, and is unconditionally guaranteed by each of our subsidiaries other than Ellwood Pipeline, Inc. The collateral also secures our obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the revolving credit facility. We, along with the administrative agent under the revolving credit facility and the collateral trustee under the collateral trust agreement, entered into an intercreditor agreement dated as of March 31, 2006 that governs matters relating to the priority, enforcement and other rights relating to such security, including the order in which the proceeds of such security will be distributed, between the administrative agent under the revolving credit facility, as holder of the first priority lien on such security, and the collateral trustee, as holder of the second priority lien on such security. The revolving credit facility will mature on March 30, 2009, and may be prepaid at any time without penalty or premium at our option. The revolving credit facility is subject to mandatory prepayment in certain events, including (i) if, and to the extent that, outstanding borrowings exceed the borrowing base (including following a sale of assets) and (ii) in the event of a mandatory or optional prepayment of amounts borrowed under the second lien term loan facility using proceeds from the issuance of equity or debt or from an asset disposition to the extent necessary to reduce outstanding borrowings under the revolving credit facility to no greater than 75% of the borrowing base. The borrowing base will be redetermined twice each year in May and November, based on reserve reports prepared as of January 1 and July 1 of such year. In addition, we and the lenders may request a limited number of additional borrowing base redeterminations.

        Loans made under the revolving credit facility are designated, at our option, as either "Base Rate Loans" or "LIBO Rate Loans." Base Rate Loans bear interest at a floating rate equal to (i) the greater of Bank of Montreal's announced base rate and the overnight federal funds rate plus 0.5% plus (ii) an applicable margin ranging from 0.50% to 1.25%, based upon the percentage of the total borrowing base represented by outstanding borrowings. LIBO Rate Loans bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 2.0% to 2.75%, also based upon utilization. A commitment fee ranging from 0.375% to 0.5% per annum is payable with respect to unused borrowing availability under the revolving credit facility. If we complete a qualifying IPO, the applicable margin for both Base Rate Loans and LIBO Rate Loans will decrease by 0.50%, and, if we do not complete a qualifying IPO by January 2, 2007, the applicable margin on those loans will increase by 0.25%. A "qualifying IPO" is defined as a firm commitment underwritten offering of capital stock pursuant to which we receive net cash proceeds (net of underwriting discounts and commissions) of at least $200.0 million.

        The revolving credit facility contains a number of restrictive and financial covenants and other terms customary in a credit facility secured by oil and natural gas properties. The covenants place restrictions and limitations on our ability to, among other things:

    incur additional debt;

    grant additional liens on our assets;

    enter into transactions with our affiliates;

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    dispose of our assets or merge with another entity;

    engage in other lines of business;

    pay dividends;

    make capital expenditures;

    repurchase stock;

    make a mandatory or optional prepayment of amounts borrowed under the second lien term loan facility;

    enter into forward sales contracts outside the ordinary course of business covering oil or natural gas production;

    sell or convey production payments or similar property interests; and

    make certain investments or certain acquisitions of hydrocarbon interests or other assets.

        The revolving credit facility also prohibits us from amending the terms of the senior notes and the second lien term loan facility in any material respect or from prepaying or redeeming the senior notes other than with the proceeds of an equity offering. Financial covenants in the revolving credit facility require us to, among other things:

    maintain a specified ratio of consolidated total debt to consolidated EBITDA (measured over a rolling four-quarter period and giving effect to the TexCal transaction);

    maintain a ratio of current assets plus unused availability under the revolving credit facility to current liabilities, excluding the current portion of indebtedness outstanding under the revolving credit facility, of at least 1 to 1;

    maintain a specified ratio of consolidated EBITDA to consolidated interest expense (measured over a rolling four-quarter period and giving effect to the TexCal transaction); and

    for so long as the second lien term loan facility is outstanding, maintain a specified ratio of net present value of our properties to consolidated total debt.

        The revolving credit facility also prohibits us from entering into hedging transactions covering more than 80% of projected production from our proved developed producing oil and natural gas reserves. The facility requires us to maintain hedging contracts that cover a minimum of 50% of our projected oil and natural gas production.

        Events of default under the revolving credit facility include, among others:

    our failure to make timely payments of principal and interest due under the revolving credit facility;

    our breach of any representation or warranty or our failure to comply with any covenant under the revolving credit facility or with any material third party agreement;

    our bankruptcy, insolvency or other similar event;

    certain changes of control;

    defaults under the second lien term loan facility or the senior note indenture;

    default on other indebtedness in excess of $5 million;

    material judgments against us in excess of $5 million;

    loss of a material governmental license or permit; and

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    occurrence of a material adverse effect with respect to our operations, business, properties or financial condition.

        Upon the occurrence of an event of default under the revolving credit facility, the lenders may, among other things, terminate their commitments, declare our indebtedness immediately due and payable and foreclose on and sell our properties.

Second Lien Term Loan Facility

        On March 30, 2006, we entered into the second lien term loan facility with Credit Suisse, Cayman Islands Branch, as administrative agent, Credit Suisse Securities (USA) LLC and Lehman Brothers Inc., as joint lead arrangers, Harris Nesbitt Corp., as co-arranger, and Lehman Brothers Inc., as syndication agent. The second lien term loan facility was amended and restated as of April 28, 2006. We borrowed $350.0 million under the second lien term loan facility on March 30, 2006 to finance part of the purchase price of the TexCal transaction.

        The second lien term loan facility is secured by second priority liens on the same collateral as the revolving credit facility. A collateral trust agreement has been entered into in order to provide, for the benefit of the holders of our senior notes, liens on our property that are equal and ratable with the liens securing the second lien term loan facility. Following this offering and the application of the proceeds as set forth in "Use of Proceeds," the senior notes will no longer be secured. See "—Senior Notes." Principal on the second lien term loan facility is payable on March 30, 2011. Offers to prepay the second lien term loan facility are required upon a sale of assets, a receipt of insurance or condemnation proceeds, issuance of capital stock (including the issuance of common stock in this offering), or an incurrence of indebtedness, subject to prior obligations to reduce borrowings under the revolving credit facility to specified levels and to compliance with restrictions in the revolving credit facility on payment of the second lien term loan facility. Mandatory prepayments with proceeds of an equity offering vary from zero to 50% of such net proceeds, depending on our consolidated leverage ratio at the time of such repayment. Any lender under the second lien term loan facility may decline to accept its pro rata share of any such mandatory prepayment. We may from time to time make optional prepayments on outstanding loans. Under the second lien term loan facility, optional prepayments made prior to March 30, 2007 are subject to a prepayment premium of 2%, declining to 1% after March 30, 2007 and until March 30, 2008.

        Base Rate Loans under the second lien term loan facility bear interest at a floating rate equal to (i) the greater of the announced base rate of the administrative agent and the overnight federal funds rate plus 0.50% plus (ii) an applicable margin ranging from 3.00% to 3.50%. LIBO Rate Loans under the second lien term loan facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 4.00% to 4.50%. The applicable margin will decrease to the lower level upon completion of a qualifying IPO for as long as our consolidated leverage ratio is less than 3:1.

        The agreement governing the second lien term loan facility, as amended, contains substantially the same covenants, including financial covenants and events of default, as in the revolving credit facility, except that (i) the second lien term loan facility is less restrictive with respect to dispositions of assets, (ii) the general debt basket for the second lien term loan is $10.0 million, compared to $5.0 million for the revolving credit facility, (iii) the second lien term loan facility permits additional investments of up to $10.0 million and (iv) the second lien term loan facility permits the incurrence of up to $200.0 million of unsecured indebtedness if, among other things, no payments are required in respect of such indebtedness until six months after March 30, 2011.

Senior Notes

        We issued $150 million of our senior notes in December 2004. The notes bear interest at 8.75% per year and will mature on December 15, 2011. The notes represent senior obligations and rank pari passu with all of our existing and future senior indebtedness and senior to all of our existing and future

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subordinated indebtedness. The notes are unconditionally guaranteed, jointly and severally, by all of our subsidiaries other than Ellwood Pipeline, Inc., on a senior basis. The notes were issued as unsecured obligations subject to a covenant requiring that they be equally and ratably secured in the event of certain secured borrowings that do not constitute "permitted liens" (as defined). In accordance with this provision, on March 30, 2006, we entered into a collateral trust agreement the effect of which is to secure the notes equally and ratably with the second lien term loan facility. Subsequent to this offering, we expect that all of our secured borrowings will constitute permitted liens, and as a result, that the senior notes will again be unsecured.

        Under the indenture governing the notes, we may redeem the notes, in whole or in part, at any time on or after December 15, 2008, at a redemption price equal to 104.375% of the principal amount of the redeemed notes if the redemption occurs in the twelve-month period beginning on December 15, 2008, 102.188% of the principal amount if the redemption occurs in the twelve-month period beginning on December 15, 2009 and 100% of the principal amount if the redemption occurs on December 15, 2010 or later, in each case together with any accrued and unpaid interest to the date of redemption. In addition, before December 15, 2008, we may redeem all or part of the notes at a "make-whole" price equal to the greater of (i) 100% of the principal amount of the notes to be redeemed and (ii) the sum of the present values of (a) 104.375% of the principal amount and (b) the remaining scheduled payments of interest from the redemption date to December 15, 2008 discounted back to the redemption date on a semi-annual basis at an interest rate determined with reference to U.S. Treasury securities plus 50 basis points, plus, in the case of both (i) and (ii), accrued and unpaid interest to the redemption date.

        Before December 15, 2007, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the notes with the net proceeds of certain public or private equity offerings at a redemption price of 108.75% of the principal amount of the notes, plus any accrued and unpaid interest, if at least 65% of the aggregate principal amount of the notes issued under the indenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering.

        Upon the occurrence of a "change of control" of our company (as defined), each holder of notes may require us to repurchase all or a portion of its notes for cash at a price equal to 101% of the aggregate principal amount of those notes, plus any accrued and unpaid interest.

        The indenture governing the notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

    make investments;

    incur additional indebtedness or issue preferred stock;

    create certain liens;

    sell assets;

    enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

    consolidate, merge or transfer all or substantially all of the assets of our company and our restricted subsidiaries taken as a whole;

    engage in transactions with affiliates;

    pay dividends or make other distributions on capital stock or subordinated indebtedness;

    repurchase or redeem capital stock;

    enter into different lines of business;

    create unrestricted securities; and

    enter into sale and leaseback transactions.

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UNDERWRITING

        Under the terms and subject to the conditions contained in an underwriting agreement dated                        , 2006, we and the selling stockholders have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC, Lehman Brothers Inc. and J.P. Morgan Securities Inc. are acting as representatives and book-running managers, the following number of shares of common stock:

Underwriter

  Number of
Shares

Credit Suisse Securities (USA) LLC    
Lehman Brothers Inc.     
J.P. Morgan Securities Inc.     
A.G. Edwards & Sons, Inc.     
BMO Capital Markets Corp.     
   
  Total   12,500,000
   

        The underwriting agreement provides that the underwriters are obligated to purchase all of the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

        We and the selling stockholders have granted to the underwriters a 30-day option to purchase up to 1,875,000 additional shares at the initial public offering price less the underwriting discounts. The option may be exercised only to cover any over-allotments of common stock.

        The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $                  per share. The underwriters and selling group members may allow a discount of $                  per share on sales to other broker/dealers. After the initial public offering, the representatives may change the public offering price and concession and discount to broker/dealers.

        We have agreed to pay expenses incurred by the selling stockholders in connection with the offering, other than underwriting discounts. The following table summarizes the compensation and estimated expenses we and the selling stockholders will pay:

 
  Per Share
  Total
 
  Without
Over-allotment

  With
Over-allotment

  Without
Over-allotment

  With
Over-allotment

Underwriting Discounts Paid by Us   $     $     $     $  
Expenses Payable by Us   $     $     $     $  
Underwriting Discounts Paid by Selling Stockholders   $     $     $     $  

        The underwriters will not confirm sales to any accounts over which they exercise discretionary authority without first receiving a written consent from those accounts.

        We intend to use more than 10% of the net proceeds from the sale of shares to repay indebtedness owed by us to Credit Suisse, Cayman Islands Branch, Lehman Commercial Paper Inc. and Bank of Montreal, affiliates of certain of the underwriters. Accordingly, the offering is being made in compliance with the requirements of Rule 2710(h) of the National Association of Securities Dealers, Inc. Conduct Rules. This rule provides generally that if more than 10% of the net proceeds from the sale of stock, not including underwriting compensation, is paid to the underwriters or their

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affiliates, the initial public offering price of the stock may not be higher than that recommended by a "qualified independent underwriter" meeting certain standards. Accordingly, J.P. Morgan Securities Inc. is assuming the responsibilities of acting as the qualified independent underwriter in pricing the offering and conducting due diligence. The initial public offering price of the shares of common stock is no higher than the price recommended by J.P. Morgan Securities Inc.

        We have agreed that we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission, or exercise any right with respect to the filing of a registration statement under the Securities Act of 1933 (other than the registration statement on Form S-8 we intend to file following completion of this offering) relating to, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC, Lehman Brothers Inc. and J.P. Morgan Securities Inc. for a period of 180 days after the date of this prospectus. The foregoing restrictions will not apply to private issuances of securities in connection with acquisitions (provided the recipients of such securities agree to be subject to similar restrictions) or to grants of awards under our existing stock incentive plans or the issuance of common stock upon the exercise of currently outstanding stock options. However, in the event that either (i) during the last 17 days of the "lock-up" period, we release earnings results or material news or a material event relating to us occurs or (ii) prior to the expiration of the "lock-up" period, we announce that we will release earnings results during the 16-day period beginning on the last day of the "lock-up" period, then in either case the expiration of the "lock-up" will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC, Lehman Brothers Inc. and J.P. Morgan Securities Inc. waive, in writing, such an extension.

        Except pursuant to this offering and the exercise of the over-allotment option, if any, certain of our officers, our directors and the selling stockholders have agreed not to offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC, Lehman Brothers Inc. and J.P. Morgan Securities Inc. for a period of 180 days after the date of this prospectus. However, in the event that either (i) during the last 17 days of the "lock-up" period, we release earnings results or material news or a material event relating to us occurs or (ii) prior to the expiration of the "lock-up" period, we announce that we will release earnings results during the 16-day period beginning on the last day of the "lock-up" period, then in either case the expiration of the "lock-up" will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC, Lehman Brothers Inc. and J.P. Morgan Securities Inc. waive, in writing, such an extension.

        The underwriters have reserved for sale at the initial public offering price up to 937,500 shares of our shares for sale under a directed share program to our officers, directors, employees and other persons associated with us who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares. Participants in

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the directed share program will be subject to lock-up agreements with terms substantially similar to those described in the preceding paragraph.

        We and the selling stockholders have agreed to indemnify the underwriters and J.P. Morgan Securities Inc., in its capacity as a qualified independent underwriter, against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

        We have applied to list the shares of our common stock on the New York Stock Exchange under the symbol "VQ". In connection with the listing of the common stock on the New York Stock Exchange, the underwriters have undertaken to sell at least the minimum number of shares to at least the minimum number of beneficial owners necessary to meet New York Stock Exchange listing requirements.

        We and our subsidiaries may from time to time enter into other investment banking relationships with the underwriters or their affiliates pursuant to which the underwriters will receive customary fees and will be entitled to reimbursement for all related reasonable disbursements and out-of-pocket expenses. We expect that any arrangement will include provisions for the indemnification of the underwriters against a variety of liabilities, including liabilities under the federal securities laws. Lehman Brothers Inc. and Harris Nesbitt Corp. (now BMO Capital Markets Corp.) acted as initial purchasers of our senior notes in December 2004 and received customary compensation in such capacity. Credit Suisse Securities (USA) LLC, Lehman Brothers Inc., BMO Capital Markets Corp. and certain of their respective affiliates are serving as agents, arrangers and lenders under our revolving credit agreement and our term loan agreement for which they have received customary compensation in such capacities. Pursuant to these credit facilities we have also agreed to indemnify such persons against a variety of liabilities and to reimburse certain expenses.

        Prior to this offering, there has been no public market for our common stock. The initial public offering price for our common stock will be determined by negotiation between us, the Marquez Trust and the underwriters. The principal factors to be considered in determining the initial public offering price include the following:

    the general condition of the securities markets;

    market conditions for initial public offerings;

    the market for securities of companies in businesses similar to ours;

    the history and prospects for the industry in which we compete;

    our past and present operations and earnings and our current financial position;

    the history of and prospects for our business;

    an assessment of our management; and

    other information included in this prospectus and otherwise available to the underwriters.

        There can be no assurance that the initial public offering price will correspond to the price at which our common stock will trade in the public market subsequent to this offering or that an active trading market will develop and continue after this offering.

        In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.

    Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

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    Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that it may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.

    Syndicate covering transactions involve purchases of common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

    Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

        A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

        Each of the underwriters has represented, warranted and agreed as follows:

    (a)
    it has not made or will not make an offer of shares to the public in the United Kingdom within the meaning of section 102B of the Financial Services and Markets Act 2000 (as amended) (FSMA) except to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities or otherwise in circumstances which do not require the publication by the company of a prospectus pursuant to the Prospectus Rules of the Financial Services Authority (FSA);

    (b)
    it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of FSMA) to persons who have professional experience in matters relating to investments falling with Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 or in circumstances in which section 21 of FSMA does not apply to the company; and

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    (c)
    it has complied with, and will comply with all applicable provisions of FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

        In relation to each Member State of the European Economic Area (each, a "Relevant Member State") that has implemented the Prospectus Directive (as defined below), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the "Relevant Implementation Date") it has not made and will not make an offer of securities to the public in that Relevant Member State prior to the publication of a prospectus in relation to the securities which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of securities to the public in that Relevant Member State at any time, (a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities; (b)  to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; (c)  to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the manager for any such offer; or (d)  in any other circumstances which do not require the publication by us of a prospectus pursuant to Article 3 of the Prospectus Directive.

        For the purposes of this provision, the expression an "offer of shares to the public" in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe for the shares, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State. The expression "Prospectus Directive" means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
FOR NON-UNITED STATES HOLDERS

        The following is a summary of material United States federal income and estate tax considerations relating to the purchase, ownership and disposition of our common stock by persons that are non-United States holders (as defined below), but does not purport to be a complete analysis of all the potential tax considerations relating thereto. This summary is based upon the Internal Revenue Code of 1986, as amended (the "Code"), administrative rulings and court decisions, all of which are subject to change, possibly on a retroactive basis. We undertake no obligation to update this summary in the future. This summary deals only with non-United States holders that will hold our common stock as "capital assets" (generally, property held for investment) and does not address tax considerations applicable to investors that may be subject to special tax rules, including financial institutions, tax-exempt organizations, insurance companies, qualified retirement plans or individual retirement accounts, dealers in securities or currencies, traders in securities that elect to use a mark-to-market method of accounting for their securities holdings, persons that will hold the common stock as a position in a hedging transaction, "straddle" or "conversion transaction" for tax purposes, regulated investment companies, real estate investment trusts, persons that have a "functional currency" other than the U.S. dollar, "controlled foreign corporations," "passive foreign corporations," corporations that accumulate earnings to avoid U.S. federal income tax, or partnerships or other pass-through entities or holders of an interest in such entities. Such persons should consult with their own tax advisors to determine the U.S. federal income and estate tax consequences that may be relevant to them. If a partnership holds the common stock, the tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership (including an entity treated as a partnership for United States federal income tax purposes) holding our common stock, you should consult your tax advisor. Moreover, this summary does not discuss alternative minimum tax consequences, if any, or any state, local or foreign tax consequences to holders of the common stock. We have not sought any ruling from the Internal Revenue Service (the "IRS") with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS will agree with such statements and conclusions. INVESTORS CONSIDERING THE PURCHASE OF COMMON STOCK SHOULD CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE UNITED STATES FEDERAL INCOME AND ESTATE TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES ARISING UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.

        As used in this discussion, a "non-United States holder" is a beneficial owner of common stock (other than a partnership) that for United States federal income tax purposes is not:

    an individual who is a citizen or resident of the United States, including an alien individual who is a lawful permanent resident of the United States or who meets the "substantial presence" test under Section 7701(b) of the Code.

    a corporation, or other entity taxable as a corporation for United States federal income tax purposes, that was created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

    an estate whose income is subject to United States federal income taxation regardless of its source; or

    a trust (i) if it is subject to the supervision of a court within the United States and one or more United States persons have the authority to control all substantial decisions of the trust or (ii) that has a valid election in effect under applicable United States Treasury Regulations to be treated as a United States person.

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Distributions on Our Common Stock

        We have no plans to declare or pay any dividends on our common stock. However, if we do pay a dividend on our common stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of earnings and profits will constitute a return of capital that is applied against and reduces the non-United States holder's adjusted tax basis in our common stock. Any remaining excess will be treated as gain realized on the sale or other disposition of the common stock and will be treated as described under "Gain on Disposition of Common Stock" below. Any dividend paid to a non-United States holder of common stock ordinarily will be subject to withholding of United States federal income tax at a rate of 30%, or such lower rate as may be specified under an applicable income tax treaty. In order to receive a reduced treaty rate, a non-United States holder must provide us with IRS Form W-8BEN or other appropriate version of Form W-8 certifying eligibility for the reduced rate.

        Dividends paid to a non-United States holder that are effectively connected with a trade or business conducted by the non-United States holder in the United States (and, where a tax treaty applies, are attributable to a permanent establishment maintained by the non-United States holder in the United States) generally will be exempt from the withholding tax described above and instead will be subject to United States federal income tax on a net income basis at the regular graduated U.S. federal income tax rates in much the same manner as if the non-United States holder were a resident of the United States. In such cases, we will not have to withhold U.S. federal income tax if the non-United States holder complies with applicable certification and disclosure requirements. In order to obtain this exemption from withholding tax, a non-United States holder must provide us with an IRS Form W 8ECI properly certifying eligibility for such exemption. Dividends received by a corporate non-United States holder that are effectively connected with a trade or business conducted by such corporate non-United States holder in the United States may also be subject to an additional branch profits tax at a rate of 30% or such lower rate as may be specified by an applicable tax treaty.

Gain on Disposition of Common Stock

        Generally, a non-United States holder will not be subject to United States federal income tax with respect to gain recognized upon the disposition of such non-United States holder's shares of common stock unless:

    We are or have been a "United States real property holding corporation" ("USRPHC"), for U.S. federal income tax purposes (i.e., a domestic corporation whose trade or business and real property assets consist primarily of "United States real property interests") and, if our common stock is "regularly traded on an established securities market," the non-United States holder held, directly or constructively, at any time during the five-year period ending on the date of disposition or such shorter period that such shares were held, more than five percent of our common stock;

    The non-United States holder is an individual who is present in the United States for 183 days or more in the taxable year of disposition and certain other conditions are met; or

    Such gain is effectively connected with the conduct by the non-United States holder of a trade or business within the United States (or, if a tax treaty applies, the gain is attributable to a United States permanent establishment maintained by the non-United States holder).

        With respect to the first bullet point above, we believe that we currently are, and expect to be for the foreseeable future, a USRPHC as a result of our interests in oil and natural gas assets that qualify as United States real property interests. However, when and for so long as our common stock is not "regularly traded on an established securities market," a non-United States shareholder will be taxable

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on gain recognized on the sale of our common stock. On the other hand, if and when our common stock is "regularly traded on an established securities market," a non-United States holder will be taxable on gain recognized on the sale of our common stock only if the non-United States holder actually or constructively holds more than 5% of such common stock at any time during the applicable period described in the first bullet point above. For so long as 100 or fewer people own 50% or more of our common stock, our common stock will be considered "regularly traded" only if it is traded on an established securities market located in the United States and is regularly quoted by brokers or dealers making a market in our common stock. Our common stock may be considered "regularly traded" upon the completion of this offering. Because the determination of whether our stock is "regularly traded" is a factual question, however, there can be no assurance that our stock will be "regularly traded" at that time. If a non-United States holder were subject to United States federal income tax as a result of our status as a USRPHC, any gain or loss on the disposition of the stock would be taken into account as if it were effectively connected with the conduct by the non-United States holder of a trade or business within the United States. Any such gain generally would be taxable to the non-United States holder at United States federal income tax rates applicable to capital gains, as described below.

        An individual non-U.S. holder described in the second bullet point above will be subject to a flat 30% tax on the gain derived from the sale, which may be offset against U.S. source capital losses (even though the individual is not considered a resident of the United States).

        A non-U.S. holder described in the third bullet point above will be subject to United States federal income tax on the gain recognized from the sale under regular graduated U.S. federal income tax rates and, if it is a corporation, may be subject to the branch profits tax at a rate equal to 30% (or such lower rate as may be prescribed by an applicable treaty).

Tax Rates on Distributions and Capital Gains

        A distribution on common stock taxed as an effectively connected dividend may be eligible for the 15% maximum United States federal income tax rate that applies to dividends received by individuals before January 1, 2009. Effectively connected ordinary income generally is subject to a maximum United States federal income tax rate of 35%.

        Effectively connected long-term capital gains from the disposition of common stock by individuals subject to tax under regular graduated United States federal income tax rates are generally subject to a 15% maximum United States federal income tax rate for capital gains recognized before January 1, 2009. Deductions for capital losses are subject to limitations.

Federal Estate Taxes

        The estate of a non-United States holder of common stock may be subject to United States estate tax on the value of the common stock, which is considered United States situs property for such purposes. United States estate tax is imposed at graduated rates, the highest of which is currently 47%. An estate tax credit is currently available for the estates of non-residents, the effect of which is to exempt up to $60,000 of United States situs property. If the non-United States holder is a qualified resident of a country with which the United States maintains an estate tax treaty, an increased exemption from United States estate tax may be available.

Information Reporting and Backup Withholding

        Generally, we must report annually to the IRS and to each non-United States holder the amount of dividends paid to such holder, such holder's name and address, and the amount, if any, of tax withheld. Copies of the information returns reporting those dividends and amounts withheld may also be made available to the tax authorities in the country in which such holder resides under the provisions of any applicable tax treaty or exchange of information agreement.

120



        In general, backup withholding at the applicable rate (currently 28%) will not apply to dividends on our common stock paid by us or our paying agents, in their capacities as such, to a non-United States holder if such non-United States holder has provided the required certification and neither we nor our paying agent has actual knowledge or reason to know that the payee is a United States person.

        Information reporting and backup withholding generally will not apply to a payment of the proceeds of a sale of common stock effected outside the United States by a foreign office of a foreign broker. However, information reporting requirements will apply to a payment of the proceeds of a sale of common stock effected outside the United States by a foreign office of a broker if the broker (i) is a United States person, (ii) derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States, (iii) is a "controlled foreign corporation" as to the United States, or (iv) is a foreign partnership that, at any time during its taxable year, is more than 50% (by income or capital interests) owned by United States persons or is engaged in the conduct of a trade or business in the United States, unless in any such case the broker has documentary evidence in its records that the beneficial owner is a non-United States holder and certain other conditions are met, or the holder otherwise establishes an exemption. Payment of the proceeds of a sale of common stock by a United States office of a broker will be subject to both information reporting and backup withholding unless the holder certifies its non-United States holder status under penalties of perjury and the broker does not have actual knowledge or reason to know that the payee is a United States person, or otherwise establishes an exemption.

        Backup withholding is not an additional tax. Any amount withheld under the backup withholding rules will be allowed as a credit against the non-United States holder's United States federal income tax liability and any excess may be refundable if the proper information is provided to the IRS.

121



LEGAL MATTERS

        Davis Graham & Stubbs LLP will pass upon the validity of the common stock on our behalf. Certain matters with respect to United States law will be passed upon by Akin Gump Strauss Hauer & Feld, LLP on behalf of the underwriters.


EXPERTS

        Our financial statements as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph referring to the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations," on January 1, 2003) and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        The financial statements of TexCal Energy (LP) LLC and its predecessor, included in this prospectus, have been audited by BDO Seidman, LLP, an independent registered public accounting firm, to the extent and for the periods set forth in their report appearing elsewhere herein (which report expresses an unqualified opinion and includes an explanatory paragraph referring to the adoption of SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003), and are included in reliance upon such report given upon the authority of said firm as experts in auditing and accounting.

        Estimates of our oil and natural gas reserves and related information as of December 31, 2005 and December 31, 2004 included in this prospectus have been derived from engineering reports prepared by Netherland, Sewell & Associates, Inc. Estimates of our oil and natural gas reserves and related information as of December 31, 2003 included in this prospectus have been derived from engineering reports prepared by Ryder Scott Company, L.P. Estimates of our oil and natural gas reserves and related information as of July 31, 2006 included in this prospectus have been derived from an engineering report prepared by DeGolyer & MacNaughton with respect to certain of our properties and an engineering report prepared by Netherland, Sewell & Associates, Inc. with respect to the remainder. The estimates have been so included in reliance upon the reports of those firms given upon their authority as experts in petroleum engineering.


WHERE YOU CAN FIND MORE INFORMATION

        We have filed with the SEC a registration statement on Form S-1 with respect to the common stock offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules that are part of the registration statement. Statements made in this prospectus regarding the contents of any contract or other documents are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. In addition, we are required to file periodic and current reports and other information with the SEC by reason of the registration of our senior notes under the Securities Act. For further information pertaining to us and to the common stock offered by this prospectus, reference is made to the registration statement and those periodic and current reports, including the exhibits and schedules thereto, copies of which may be inspected without charge at the Public Reference Room of the SEC at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information regarding the operation of the Public Reference Room. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed electronically with the SEC. The web site can be accessed at www.sec.gov.

122



INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 
Venoco, Inc.:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2004 and 2005 and June 30, 2006 (unaudited)

Consolidated Statements of Operations for the Years Ended December 31, 2003, 2004 and 2005 and the Six Months Ended June 30, 2005 and 2006 (unaudited)

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2003, 2004 and 2005 and the Six Months Ended June 30, 2005 and 2006 (unaudited)

Consolidated Statements of Changes in Stockholders' Equity for the Years Ended December 31, 2003, 2004 and 2005 and the Six Months Ended June 30, 2006 (unaudited)

Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2004 and 2005 and the Six Months Ended June 30, 2005 and 2006 (unaudited)

Notes to Consolidated Financial Statements

TexCal Energy (LP) LLC:

Independent Auditor's Report

Consolidated Balance Sheets as of December 31, 2004 and 2005 (Successor)

Consolidated Statements of Operations for the Year Ended December 31, 2003 (Predecessor), the Nine Months Ended September 30, 2004 (Predecessor), from Inception (October 1, 2004) to December 31, 2004 (Successor) and for the Year Ended December 31, 2005 (Successor)

Consolidated Statements of Capital Deficit for the Year Ended December 31, 2003 (Predecessor), the Nine Months Ended September 30, 2004 (Predecessor), and Statements of Members' Equity from Inception (October 1, 2004) to December 31, 2004 (Successor) and for the Year Ended December 31, 2005 (Successor)

Consolidated Statements of Cash Flows for the Year Ended December 31, 2003 (Predecessor), the Nine Months Ended September 30, 2004 (Predecessor), from Inception (October 1, 2004) to December 31, 2004 (Successor) and for the Year Ended December 31, 2005 (Successor)

Notes to Consolidated Financial Statements

F-1



REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Venoco, Inc.
Denver, Colorado

        We have audited the accompanying consolidated balance sheets of Venoco, Inc. and subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of operations, comprehensive income, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Venoco, Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 13 to the consolidated financial statements, the Company implemented the provision of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
April 5, 2006

F-2



VENOCO, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares amounts)

 
  December 31,
   
 
 
  June 30,
2006

 
 
  2004
  2005
 
 
  (Successor)

  (Successor)

  (Successor)
(unaudited)

 
ASSETS                    
CURRENT ASSETS:                    
  Cash and cash equivalents   $ 54,715   $ 9,389   $ 13,387  
  Accounts receivable, net of allowance for doubtful accounts of $100, $759 and $1,218 at December 31, 2004 and 2005 and June 30, 2006, respectively     17,755     29,841     40,669  
  Inventories     1,079     1,753     2,177  
  Prepaid expenses and other current assets     3,431     4,351     5,238  
  Notes receivable—officers     1,420          
  Income tax receivable     3,906     4,107     2,811  
  Deferred income taxes     209     8,611     9,673  
  Commodity derivatives     5,300     3,391     7,507  
   
 
 
 
    Total current assets     87,815     61,443     81,462  
   
 
 
 
PROPERTY, PLANT AND EQUIPMENT, AT COST:                    
  Oil and natural gas properties (full cost method, of which $3,317, $2,275 and $3,732 for unproved properties were excluded from amortization at December 31, 2004 and 2005 and June 30, 2006, respectively)     214,842     269,922     811,916  
  Drilling equipment     7,594     7,947     9,956  
  Other property and equipment     25,857     27,424     16,133  
   
 
 
 
    Total property, plant and equipment     248,293     305,293     838,005  
  Accumulated depletion, depreciation and amortization     (49,730 )   (71,517 )   (94,782 )
   
 
 
 
      Net property, plant and equipment     198,563     233,776     743,223  
   
 
 
 
OTHER ASSETS:                    
  Commodity derivatives     4,855     69     6,642  
  Deferred loan costs     6,596     5,658     18,400  
  Other     1,053     1,612     3,572  
   
 
 
 
    Total other assets     12,504     7,339     28,614  
   
 
 
 
TOTAL ASSETS   $ 298,882   $ 302,558   $ 853,299  
   
 
 
 

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

 

 

 

 

 

 

 

 

 

 
CURRENT LIABILITIES:                    
  Accounts payable and accrued liabilities   $ 18,984   $ 31,134   $ 43,347  
  Undistributed revenue payable     4,774     2,155     10,817  
  Interest payable     401     720     11,379  
  Current maturities of long-term debt     127     126      
  Commodity derivatives     1,520     26,397     33,344  
  Repurchase of common stock     5,316          
   
 
 
 
    Total current liabilities     31,122     60,532     98,887  
   
 
 
 
LONG-TERM DEBT     163,542     178,943     658,777  
DEFERRED INCOME TAXES     32,208     24,108     24,635  
COMMODITY DERIVATIVES         11,992     29,394  
ASSET RETIREMENT OBLIGATIONS     23,184     22,649     34,418  
OTHER LONG-TERM LIABILITIES             1,901  
   
 
 
 
    Total liabilities     250,056     298,224     848,012  
   
 
 
 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

 

 

 

 

 
MINORITY INTEREST     387          

STOCKHOLDERS' EQUITY:

 

 

 

 

 

 

 

 

 

 
  Common stock, $.01 par value (200,000,000 shares authorized; 32,692,500 shares issued and outstanding at December 31, 2004 and 2005 and June 30, 2006)     327     327     327  
  Additional paid-in capital     31,085     20,976     21,761  
  Retained earnings (accumulated deficit)     15,104     (3,785 )   (2,610 )
  Accumulated other comprehensive income (loss)     1,923     (13,184 )   (14,191 )
   
 
 
 
    Total stockholders' equity     48,439     4,334     5,287  
   
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY   $ 298,882   $ 302,558   $ 853,299  
   
 
 
 

See notes to consolidated financial statements.

F-3



VENOCO, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

 
  Years Ended December 31,
  Six Months Ended
June 30,

 
 
  2003
  2004
  2005
  2005
  2006
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
 
   
   
   
  (unaudited)

 
REVENUES:                                
  Oil and natural gas sales   $ 109,754   $ 139,961   $ 191,092   $ 87,390   $ 127,374  
  Commodity derivative losses—realized     (10,272 )   (17,589 )   (22,870 )   (7,155 )   (12,789 )
  Commodity derivative losses—unrealized         (1,096 )   (34,725 )   (27,999 )   (14,977 )
  Other     5,253     5,457     4,456     2,091     3,380  
   
 
 
 
 
 
    Total revenues     104,735     126,733     137,953     54,327     102,988  
   
 
 
 
 
 
EXPENSES:                                
  Oil and natural gas production     45,617     49,567     54,038     24,282     35,518  
  Transportation expense     2,785     2,915     2,596     1,216     1,610  
  Depletion, depreciation and amortization     16,161     16,489     21,680     9,493     23,497  
  Accretion of abandonment liability     1,401     1,482     1,752     1,018     1,111  
  General and administrative, net of amounts capitalized     11,632     11,272     16,007     7,699     12,121  
  Litigation settlement     6,000                  
  Amortization of deferred loan costs     370     3,050     1,755     1,021     1,471  
  Interest, net     2,125     2,269     13,673     6,820     18,629  
   
 
 
 
 
 
    Total expenses     86,091     87,044     111,501     51,549     93,957  
   
 
 
 
 
 
Income (loss) before income taxes, minority interest and cumulative effect of change in accounting principle     18,644     39,689     26,452     2,778     9,031  
INCOME TAXES:                                
  Current     3,838     5,479     13,000     6,719     2,942  
  Deferred     4,038     10,609     (2,700 )   (5,945 )   658  
   
 
 
 
 
 
    Total income taxes     7,876     16,088     10,300     774     3,600  
   
 
 
 
 
 
Net income (loss) before minority interest and cumulative effect of change in accounting principle     10,768     23,601     16,152     2,004     5,431  
Minority interest in Marquez Energy         95     42     42      
   
 
 
 
 
 
Income before cumulative effect of change in accounting principle     10,768     23,506     16,110     1,962     5,431  
Cumulative effect of change in accounting principle, net of tax     411                  
   
 
 
 
 
 
Net income (loss)     11,179     23,506     16,110     1,962     5,431  
Preferred stock dividends     (8,465 )   (7,134 )            
Excess of carrying value over repurchase price of preferred stock         29,904              
   
 
 
 
 
 
Net income applicable to common equity   $ 2,714   $ 46,276   $ 16,110   $ 1,962   $ 5,431  
   
 
 
 
 
 
Basic earnings (loss) per common share:                                
  Income (loss) before cumulative effect of change in accounting principle   $ 0.07   $ 1.33   $ 0.49   $ 0.06   $ 0.17  
  Cumulative effect of change in accounting principle     0.01                  
   
 
 
 
 
 
    Total   $ 0.08   $ 1.33   $ 0.49   $ 0.06   $ 0.17  
   
 
 
 
 
 
Diluted earnings (loss) per common share:                                
  Income (loss) before cumulative effect of change in accounting principle   $ 0.07   $ 0.48   $ 0.49   $ 0.06   $ 0.16  
  Cumulative effect of change in accounting principle     0.01                  
   
 
 
 
 
 
    Total   $ 0.08   $ 0.48   $ 0.49   $ 0.06   $ 0.16  
   
 
 
 
 
 

See notes to consolidated financial statements.

F-4



VENOCO, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

 
  Years Ended December 31,
  Six Months Ended
June 30,

 
 
  2003
  2004
  2005
  2005
  2006
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
 
   
   
   
  (unaudited)

 
Net income (loss)   $ 11,179   $ 23,506   $ 16,110   $ 1,962   $ 5,431  
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:                                
  Hedging activities:                                
    Reclassification adjustments for settled contracts(1)     1,655     1,293     (410 )   161     1,808  
    Changes in fair value of outstanding hedging positions(2)     (1,244 )   1,943     (14,697 )   (12,644 )   (2,815 )
   
 
 
 
 
 
Other comprehensive income (loss)     411     3,236     (15,107 )   (12,483 )   (1,007 )
   
 
 
 
 
 
Comprehensive income   $ 11,590   $ 26,742   $ 1,003   $ (10,521 ) $ 4,424  
   
 
 
 
 
 

(1)
Net of tax (benefit) of $1,018, $849, $(270), $106 and $1,188 for the years ended December 31, 2003, 2004 and 2005, and the six months ended June 30, 2005 and 2006, respectively.

(2)
Net of tax (benefit) of $(800), $1,276, $(9,686), $(8,338) and $(1,849) for the years ended December 31, 2003, 2004 and 2005, and the six months ended June 30, 2005 and 2006, respectively.

See notes to consolidated financial statements

F-5



VENOCO, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(In thousands)

 
  Common Stock
  Treasury Stock
   
   
  Accumulated
Other
Comprehensive
Income (Loss)

   
 
 
  Additional
Paid-in
Capital

  Retained
Earnings
(Deficit)

   
 
 
  Shares
  Amount
  Shares
  Amount
  Total
 
BALANCE AT JANUARY 1, 2003 (Predecessor)   35,890   $ 359   984   $ (1,500 ) $ (12 ) $ 2,236   $ (1,724 ) $ (641 )
  Comprehensive income:                                              
    Reclassification adjustment for settled contracts, net of tax                         1,655     1,655  
    Change in value of derivatives, net of tax                         (1,244 )   (1,244 )
  Net income                     11,179         11,179  
  Preferred stock dividends                     (8,465 )       (8,465 )
   
 
 
 
 
 
 
 
 
BALANCE AT DECEMBER 31, 2003 (Predecessor)   35,890     359   984     (1,500 )   (12 )   4,950     (1,313 )   2,484  
  Comprehensive income:                                              
    Reclassification adjustment for settled contracts, net of tax                         1,293     1,293  
    Change in value of derivatives, net of tax                         1,943     1,943  
  Net income                     23,506         23,506  
  Excess of carrying value over repurchase price of preferred stock                 29,904             29,904  
  Marquez Energy equity, net of minority interest                 1,736     1,356         3,092  
  Preferred stock dividends                     (7,134 )       (7,134 )
  Purchase accounting adjustments   (3,197 )   (32 ) (984 )   1,500     (543 )   (7,574 )       (6,649 )
   
 
 
 
 
 
 
 
 
BALANCE AT DECEMBER 31, 2004 (Successor)   32,693     327           31,085     15,104     1,923     48,439  
  Comprehensive income:                                              
    Reclassification adjustment for settled contracts, net of tax                         (410 )   (410 )
    Change in value of derivatives, net of tax                         (14,697 )   (14,697 )
  Distribution payments to Marquez Energy member, net of minority interest                 (645 )           (645 )
  Payment of dividends to shareholder                     (35,000 )       (35,000 )
  Marquez Energy acquisition adjustment                 (9,464 )   1         (9,463 )
  Net income                     16,110         16,110  
   
 
 
 
 
 
 
 
 
BALANCE AT DECEMBER 31, 2005 (Successor)   32,693   $ 327     $   $ 20,976   $ (3,785 ) $ (13,184 ) $ 4,334  
  Comprehensive income:                                              
    Reclassification adjustment for settled contracts, net of tax (unaudited)                         1,808     1,808  
    Change in value of derivatives, net of tax (unaudited)                         (2,815 )   (2,815 )
  Distribution to shareholder (unaudited)                     (4,256 )       (4,256 )
  Share-based payments, net of tax (unaudited)                 785             785  
  Net income (unaudited)                     5,431         5,431  
   
 
 
 
 
 
 
 
 
BALANCE AT JUNE 30, 2006 (Successor) (unaudited)   32,693   $ 327     $   $ 21,761   $ (2,610 ) $ (14,191 ) $ 5,287  
   
 
 
 
 
 
 
 
 

See notes to consolidated financial statements

F-6



VENOCO, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 
  Years Ended December 31,
  Six Months Ended June 30,
 
 
  2003
  2004
  2005
  2005
  2006
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
 
   
   
   
  (unaudited)

 
CASH FLOWS FROM OPERATING ACTIVITIES:                                
  Net income   $ 11,179   $ 23,506   $ 16,110   $ 1,962   $ 5,431  
  Adjustments to reconcile net income to net cash provided by operating activities:                                
    Depletion, depreciation and amortization     16,161     16,489     21,680     9,493     23,497  
    Accretion of abandonment liability     1,401     1,482     1,752     1,018     1,111  
    Cumulative effect of change in accounting principle     (411 )                
    Deferred income taxes (benefit)     4,038     10,609     (2,700 )   (5,945 )   658  
    Share-based compensation                     1,309  
    Amortization of deferred loan costs     370     3,050     1,755     1,021     1,471  
    Amortization of bond discounts             137     68     226  
    Minority interest in undistributed earnings         95     42     42      
    Unrealized commodity derivative losses and amortization of premiums     (2,691 )   1,095     36,936     29,105     17,771  
    Other     (287 )   (102 )            
  Changes in operating assets and liabilities:                                
    Accounts receivable     (1,032 )   (976 )   (12,739 )   (10,166 )   3,407  
    Inventories     93     (118 )   (674 )   (57 )   (424 )
    Prepaid expenses and other current assets     (839 )   (241 )   (873 )   (1,094 )   1,097  
    Income tax receivable     (322 )   (2,721 )   (201 )   6,719     241  
    Other assets     (114 )   (3 )   (559 )   (326 )   (736 )
    Accounts payable and accrued liabilities     5,567     (2,592 )   410     4,065     10,304  
    Undistributed revenue payable     (1,392 )   1,445     (2,619 )   3,031     (2,914 )
    Other liabilities     (164 )   (1,198 )   (92 )        
  Net premiums paid on derivative contracts         (6,511 )   (18,434 )   (10,715 )   (2,079 )
   
 
 
 
 
 
      Net cash provided by operating activities     31,557     43,309     39,931     28,221     60,370  
   
 
 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:                                
  Expenditures for oil and natural gas properties     (10,753 )   (16,346 )   (88,293 )   (32,050 )   (83,474 )
  Expenditures for drilling equipment         (22 )   (353 )   (93 )   (1,746 )
  Expenditures for other property and equipment     (32 )   (239 )   (1,460 )   (666 )   (1,554 )
  Purchase of new building         (14,653 )            
  Proceeds from sale of oil and natural gas properties     1     1,526     44,619     44,619     3,031  
  Increase in cash restricted for investment in oil and natural gas properties                 (44,619 )    
  Proceeds from sale of other property and equipment     16     228              
  Acquisition of TexCal Energy, net of cash acquired                     (447,519 )
  Acquisition of Marquez Energy, LLC         (672 )   (14,628 )   (14,628 )    
  Notes receivable—officers     237     2,188     1,420     1,390      
   
 
 
 
 
 
    Net cash used in investing activities     (10,531 )   (27,990 )   (58,695 )   (46,047 )   (531,262 )
   
 
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:                                
  Proceeds from long-term debt         272,397     59,000     23,000     504,529  
  Principal payments on long-term debt     (23,333 )   (159,654 )   (43,737 )   (12,677 )   (15,033 )
  Increase in deferred loan costs         (9,653 )   (817 )   (599 )   (14,180 )
  Purchase of preferred stock and unpaid dividends         (72,000 )            
  Dividend paid to shareholder             (35,000 )   (35,000 )   (426 )
  Contributions from Marquez Energy members         500              
  Distribution payments to Marquez Energy members         (611 )   (707 )   (707 )    
  Repurchase of common shares             (5,301 )   (5,245 )    
   
 
 
 
 
 
    Net cash (used in) provided by financing activities     (23,333 )   30,979     (26,562 )   (31,228 )   474,890  
   
 
 
 
 
 
  Net (decrease) increase in cash and cash equivalents     (2,307 )   46,298     (45,326 )   (49,054 )   3,998  
  Cash and cash equivalents, beginning of period     10,724     8,417     54,715     54,715     9,389  
   
 
 
 
 
 
  Cash and cash equivalents, end of period   $ 8,417   $ 54,715   $ 9,389   $ 5,661   $ 13,387  
   
 
 
 
 
 
Supplemental Disclosure of Cash Flow Information—                                
  Cash paid during the year for:                                
    Interest   $ 2,958   $ 2,524   $ 14,223   $ 6,979   $ 8,239  
    Income taxes   $ 4,160   $ 8,200   $ 13,400   $   $ 2,702  
Supplemental Disclosure of Noncash Activities—                                
  Accretion of preferred stock issuance fees   $ 272   $ 204   $          
  Decrease (increase) in accrued capital expenditures   $ (1,721 ) $ 5,222   $ 11,899   $ (1,391 ) $ (355 )
  Distribution of land and building   $   $   $   $   $ 13,399  
  Distribution of building note payable   $   $   $   $   $ 9,857  

        On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations". There was no impact on the Company's cash flows as a result of adopting this statement. See Note 13 for disclosure of the non-cash items recorded in the consolidated financial statements due to adoption of this statement.

See notes to consolidated financial statements.

F-7



VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2003, 2004, AND 2005 AND
SIX MONTHS ENDED JUNE 30, 2005 AND 2006 (UNAUDITED)

1.    ORGANIZATION AND NATURE OF OPERATIONS

        General—Venoco, Inc. (the "Company"), a Delaware corporation, is engaged in the business of acquiring interests in, and exploring for and developing, oil and natural gas properties with a focus offshore and onshore California.

        Condensed Consolidated Financial Statements—The condensed unaudited consolidated financial statements for the six months ended June 30, 2005 and 2006 have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All significant intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company's interim results have been reflected. The results for interim periods are not necessarily indicative of annual results.

        Stock Split—All common share amounts in the accompanying financial statements have been adjusted to reflect the one-for-1,000 reverse stock split effected on February 10, 2005 and the one-for-7,500 stock split effected on November 8, 2005.

        New Company Basis—During 2004, the Company's CEO, Tim Marquez, increased his ownership in the Company from 41% to 100%. In a transaction that closed on July 12, 2004, Mr. Marquez paid an aggregate of $16.2 million in cash for 18,509,468 shares of common stock of the Company (representing 53% of the common stock then outstanding) from two of the Company's former officers and their respective affiliates. On December 22, 2004, the Company merged with a corporation the sole stockholder of which was a trust controlled by Mr. Marquez. In the merger, the Company paid an aggregate of $5.4 million in cash for 2,212,208 shares of common stock. The merger resulted in an increase in Mr. Marquez's beneficial ownership of the Company's common stock from 94% to 100%.

        As a result of Mr. Marquez obtaining control of over 95% of the common stock of the Company on December 22, 2004, SEC Staff Accounting Bulletin No. 54 requires the acquisition by Mr. Marquez to be "pushed-down," meaning the post-transaction financial statements of the acquired entity reflect a new basis of accounting. Due to the de minimis impact on the Company's results of operations for the nine-day period ended December 31, 2004, the new company basis of accounting has been applied to the Company's financial statements as of December 31, 2004.

        The purchase price paid as a result of each transaction described above has been allocated to the underlying assets and liabilities based upon Mr. Marquez's acquired interests (53% on July 12, 2004 and 6% on December 22, 2004) in the respective fair market values of assets and liabilities at the date of each transaction. Accordingly, adjustments have been made to the historical values of assets and liabilities which reflect Mr. Marquez's acquisition of the common stock of the Company that he did not already own. Fair value was determined using a variety of valuation methods, including third party appraisals.

F-8



        The following represents the estimated values attributable to the assets acquired and liabilities assumed in Mr. Marquez's acquisition of the remaining 59% ownership in the Company. These values include the historical values attributable to Mr. Marquez's predecessor basis (in thousands).

Consideration paid for 18,509,468 common shares (53% of the total outstanding) on July 12, 2004   $ 16,185  
Consideration paid to minority shareholders as a result of statutory merger for 2,212,208 common shares (6% of the total outstanding) on December 22, 2004     5,439  
   
 
  Total purchase price   $ 21,624  
   
 
Allocation of purchase price:        
Current assets   $ 83,791  
Oil and natural gas properties     161,892  
Other property, plant and equipment     19,049  
Land     10,303  
Other non-current assets     12,468  
   
 
      287,503  
   
 
Current liabilities     29,689  
Long term debt     158,858  
Deferred incomes taxes     32,208  
Asset retirement obligation     22,408  
   
 
      243,163  
   
 
Net assets     44,340  
Historical net assets attributable to non-selling interests (Predecessor basis for Mr. Marquez's 41% ownership of the Company as of June 30, 2004)     (22,716 )
   
 
Fair value of net assets acquired   $ 21,624  
   
 

        Marquez Energy Acquisition—On March 21, 2005, the Company acquired Marquez Energy, a Colorado limited liability company that was majority-owned and controlled by Tim Marquez. Because of the common ownership of Marquez Energy and the Company, this acquisition has been recorded in a manner similar to a pooling-of-interests. Common control occurred in July 2004 when Tim Marquez acquired an additional 53% of the Company's common stock bringing his common stock holdings to 94%. The Company's financial statements have been adjusted to give effect to the acquisition of Marquez Energy as if it had occurred in July 2004. In addition, because of the common control, Tim Marquez's historical basis in Marquez Energy has been carried over and the excess purchase price of $9.4 million, net of deferred taxes, has been charged directly to equity. Oil and natural gas properties were written up to their pro rata fair values for amounts paid to minority interests. Due to the de minimis impact on Marquez Energy's results of operations for the ten-day period following the closing, the acquisition was recorded as if it had occurred on March 31, 2005.

F-9



        The following table summarizes the recording of the Marquez Energy acquisition (in thousands).

Write up of oil and natural gas properties to fair value—amount paid to minority interests   $ 3,652  
Deferred income tax asset     3,658  
Charge to equity for excess of purchase price over Mr. Marquez's historical basis, net of deferred taxes     9,831  
Credit to equity for elimination of minority interest     (367 )
   
 
Total purchase price   $ 16,774  
   
 

        The Company's 2004 statement of operations has been adjusted to add Marquez Energy operations from July 2004 forward. Operations of Marquez Energy alone for the six months ended December 31, 2004 consisted of the following (in thousands):

Natural gas sales   $ 2,501
Other revenues     322
   
Total revenues     2,823
   
Operating expenses     787
D, D &A     148
G&A and other     786
Minority interest     95
   
Total expenses     1,816
   
Net income   $ 1,007
   

        The Marquez Energy acquisition added proved reserves of approximately 2.0 MMBOE (unaudited) as of December 31, 2004 based on a reserve report prepared by Netherland, Sewell and Associates, Inc. (NSAI). The $16.8 million purchase price for Marquez Energy was based on members' equity per Marquez Energy's unaudited December 31, 2004 balance sheet as adjusted to reflect the value of its oil and natural gas properties (as determined by NSAI as of December 31, 2004) and certain other adjustments. For the purpose of calculating the purchase price, the following values were assigned to Marquez Energy's proved reserves (unaudited): (i) $1.75/Mcfe for its proved developed producing reserves, (ii) $1.00/Mcfe for its proved developed non-producing reserves and (iii) $0.75/Mcfe for its proved undeveloped reserves. Pursuant to the purchase agreement, NSAI conducted a supplemental evaluation of the Marquez Energy properties as of year-end 2005, and NSAI or another nationally recognized engineering firm will conduct a further supplemental evaluation as of year-end 2006. In the event the year-end 2006 evaluation attributes proved reserves to the Marquez Energy properties as of December 31, 2004 in excess of those reflected in NSAI's initial report, an additional payment will be made to the former holders of interests in Marquez Energy pursuant to the same formula, subject to a maximum aggregate price of $25 million. No additional payments were due as of December 31, 2005 based on the evaluation performed by NSAI at year-end 2005.

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2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        Principles of Consolidation—The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. All significant intercompany balances and transactions have been eliminated in consolidation.

        Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company's most significant financial estimates are based on remaining proved oil and natural gas reserves. Estimates of proved reserves are key components of the Company's depletion rate for oil and natural gas properties and the full cost ceiling test limitation. See Note 15—Supplemental Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited).

        Business Segment Information—The Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 131, Disclosures about Segments of an Enterprise and Related Information, establishes standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which the Company may earn revenues and incur expenses.

        The Company operates in one segment as each of its operating areas have similar economic characteristics and each meets the criteria for aggregation as defined in SFAS No. 131. All of the Company's operations involve the exploration, development and production of oil and natural gas and currently all operations are located in the United States. The Company has a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments. The Company tracks only basic operational data by area and does not maintain separate financial statement information by area. The chief decision maker measures financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, the chief decision maker freely allocates capital resources on a project-by-project basis across the Company's entire asset base to maximize profitability without regard to individual areas or segments.

        Concentration of Credit Risk—The Company's accounts receivable result from oil and natural gas sales to major oil and intrastate gas pipeline companies and to joint venture partners that own interests in properties operated by the Company. For the year ended December 31, 2003, the Company's oil and natural gas sales to three major customers represented 46 percent, 27 percent and 12 percent of the Company's total revenues. For the year ended December 31, 2004, the Company's oil and natural gas sales to three major customers represented 48 percent, 27 percent and 11 percent of the Company's total revenues. For the year ended December 31, 2005, the Company's oil and natural gas sales to three major customers represented 48 percent, 20 percent and 15 percent of the Company's total revenues. The Company recorded an allowance for doubtful accounts as of December 31, 2004 and 2005 of $0.1 million and $0.8 million, respectively, for customer accounts. As of December 31, 2005, 27%, 14%, and 12% of the total accounts receivable balance was receivable from the Company's three major customers.

        Revenue Recognition and Gas Imbalances—The Company records revenues from sales of natural gas and crude oil when title to the customer has transferred as defined in related sales contracts. This

F-11



generally occurs when a barge completes delivery, oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession. Oil revenues are generally recognized based on actual volumes of oil produced. Title to oil sold is typically transferred at the wellhead, except in the case of the South Ellwood field, where title is transferred when the barge that transports production from the field completes delivery.

        The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under-deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over- and under-deliveries or by cash settlement, as required by applicable contracts. Production imbalances are valued at the lowest of (1) the price in effect at the time of production, (2) the current market value, or (3) if a contract is in-hand, the contract price. The Company's production imbalances were not material at December 31, 2004 and 2005.

        Other revenues primarily include amounts received from purchasers of oil production to reimburse the Company for transportation and barge expenses. Transportation expense, net of pipeline tariff, is excluded from production expenses and is reflected separately as transportation expense.

        Cash and Cash Equivalents—Cash and cash equivalents consist of cash and liquid investments with an original maturity of three months or less.

        Inventories—Included in inventories are oil field materials and supplies, stated at the lower of cost or market, cost being determined by the first-in, first-out method.

        Oil and Natural Gas Properties—The Company's oil and natural gas producing activities are accounted for using the full cost method of accounting. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition of oil and natural gas properties and with the exploration for, and development of, oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

        Depletion of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. Depletion expense for the years ended December 31, 2003, 2004, and 2005 was $13.8 million, $14.8 million, and $20.5 million, respectively ($3.42, $3.63, and $4.85, respectively, per equivalent barrel of oil).

        Unproved property costs not subject to amortization consist primarily of leasehold costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves established or impairment determined. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. The Company will continue to evaluate these properties and costs which will be transferred into the amortization base as the undeveloped areas are tested. Impairment losses of $0.6 million, $0.1 million, and $0 were recorded for the years ended December 31, 2003, 2004 and 2005, respectively, in respect

F-12



of foreign properties. Interest costs capitalized as part of unproved property costs were $0.3 million and $0.4 million for the years ended December 31, 2003 and 2004, respectively. No interest costs were capitalized in 2005.

        In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are subject to a ceiling based upon the related estimated future net revenues, discounted at 10 percent, net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. The ceiling test is calculated using oil and natural gas prices in effect as of the balance sheet date. The Company uses derivative financial instruments that qualify for cash flow hedge accounting under SFAS No. 133 to hedge against the volatility of crude oil and natural gas prices, and in accordance with Securities and Exchange Commission guidelines, the Company includes estimated future cash flows from its hedging program in the ceiling test calculation. At December 31, 2004 and 2005, the Company's net capitalized costs did not exceed the ceiling.

        General and Administrative Costs and Expenses—Under the full cost method of accounting, the Company capitalizes a portion of general and administrative expenses that are directly identified with acquisition, exploration and development activities. These capitalized costs include salaries, employee benefits, costs of consulting services and other specifically identifiable costs and do not include costs related to production operations, general corporate overhead or similar activities. The Company capitalized general and administrative costs of $3.2 million, $2.3 million, and $2.5 million directly related to its acquisition, exploration and development activities during 2003, 2004 and 2005, respectively.

        Drilling Equipment and Other Property and Equipment—Drilling equipment and other property and equipment, which includes buildings, leasehold improvements, office and other equipment, are stated at cost. Depreciation and amortization are calculated using the straight-line method over the estimated useful lives of the related assets, ranging from 3 to 25 years. Depreciation and amortization expense for the years ended December 31, 2003, 2004 and 2005 was $1.7 million, $1.6 million and $1.2 million, respectively.

        Derivative Financial Instruments—The Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. On January 1, 2001, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings as a component of oil and natural gas revenues. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, the Company has designated certain derivatives as cash flow hedges for accounting purposes and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (Loss) ("OCI"), a component of Stockholders' Equity, to the extent the hedge is effective. Gains and losses are reclassified from OCI to the income statement as a component of total natural gas revenues in the period the hedged production occurs.

F-13



        In order to qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. The Company measures effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedge instrument is no longer considered highly effective. Gains and losses deferred in OCI related to cash flow hedges that are determined to be no longer highly effective remain unchanged until the related product is delivered. If it is determined that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

        The Company determines hedge ineffectiveness based on changes during the period in the price differentials between the index price of the derivative contracts (which uses a New York Mercantile Exchange ("NYMEX") index in the case of oil hedges, and NYMEX and PG&E Citygate in the case of natural gas hedges) and the contract price for the point of sale for the cash flow that is being hedged. Hedge ineffectiveness occurs only if the cumulative gain or loss on the derivative hedging instrument exceeds the cumulative change in the expected future cash flows on the hedged transaction. Ineffectiveness is recorded in earnings to the extent the cumulative changes in fair value of the actual derivative exceed the cumulative changes in fair value of the hypothetical derivative.

        Fair Value of Financial Instruments—The Company's financial instruments consist primarily of cash equivalents, accounts receivable and payable, derivatives, notes receivable from related parties and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. It is not practical to determine the fair value of notes receivable due to the related-party nature of the transactions. As of December 31, 2005, the carrying value of long-term debt approximates its fair value because the stated rate of interest approximates the market rate. See Note 4 for information regarding derivatives.

        Income Taxes—Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance.

        Environmental—The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company believes that it is in material compliance with existing laws and regulations.

F-14


        Earnings Per Share—Statement of Financial Accounting Standards No. 128, Earnings Per Share, requires presentation of "basic" and "diluted" earnings per share. Basic net income per common share of stock is calculated by dividing net income available to common stockholders by the weighted average number of common shares outstanding during each period.

        Diluted net income per common share of stock is calculated by dividing adjusted net income by the weighted average of common shares outstanding, including the effect of other dilutive securities. Adjusted net income is calculated using the if-converted method and, for periods in which shares of the Company's mandatorily redeemable convertible non-participating preferred stock were outstanding, is derived by adding dividends paid or accrued on such preferred stock back to net income and then adjusting for nondiscretionary items that (i) are based on income and (ii) would have changed had the preferred shares been converted at the beginning of the period. Potentially dilutive securities of the Company consist of outstanding in-the-money options to purchase the Company's common stock and shares into which the preferred stock may be converted.

        The treasury stock method is used to measure the dilutive impact of stock options. The following table details the weighted average dilutive and anti-dilutive securities related to stock options for the periods presented:

 
  Years ended December 31,
  Six Months Ended
June 30,

 
  2003
  2004
  2005
  2005
  2006
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
   
   
   
  (unaudited)

Dilutive   21,945     2,272,239     3,556,161
Anti-dilutive   480,731   335,764   816,553   3,556,161   619,710

        The dilutive effect of stock options is considered in the detailed calculation below.

        Shares associated with the conversion feature of the preferred stock are accounted for using the if-converted method as described above. A total of 14,528,638 potentially dilutive shares related to the preferred stock were included in the calculation of diluted net income per common share for the year ended December 31, 2004 and a total of 17,217,379 potentially dilutive shares related to the preferred stock were excluded from the calculation of diluted net income per share for the year ended December 31, 2003 because they were not dilutive. In November 2004, the Company repurchased all of the outstanding preferred stock.

F-15



        The following table sets forth the calculation of basic and diluted earnings per share (in thousands except per share amounts):

 
  Year ended December 31,
  Six months ended
June 30,

 
  2003
  2004
  2005
  2005
  2006
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
   
   
   
  (unaudited)

Net income (loss) attributable to common shareholders   $ 2,714   $ 46,276   $ 16,110   $ 1,962   $ 5,431
Adjustments to net income for dilution:                              
  Add: Preferred stock dividend if convertible preferred stock converted to equity     8,465     7,134            
  Deduct: Excess of carrying value over repurchase price of preferred stock         (29,904 )          
   
 
 
 
 
Net income (loss) adjusted for the effect of dilution   $ 11,179   $ 23,506   $ 16,110   $ 1,962   $ 5,431
   
 
 
 
 
Basic weighted average common shares outstanding     34,906     34,858     32,693     32,693     32,693
  Add: dilutive effect of stock options     8         286         1,329
  Add: dilutive effect of convertible preferred stock         14,529            
   
 
 
 
 
Diluted weighted average common shares outstanding     34,914     49,387     32,979     32,693     34,022
   
 
 
 
 
Basic earnings (loss) per common share   $ 0.07   $ 1.33   $ 0.49   $ 0.06   $ 0.17
Diluted earnings (loss) per common share   $ 0.07   $ 0.48   $ 0.49   $ 0.06   $ 0.16

        Stock-Based Compensation—The Company grants stock options to employees and non-employee directors. Until December 31, 2005, the Company accounted for stock-based compensation using the intrinsic value recognition and measurement principles prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB No. 25") and related interpretations. No compensation cost was recorded prior to January 1, 2006 as all stock options had an exercise price equal to or greater than the market value of the underlying common stock on the date of grant. The following table illustrates the pro forma effect on net income and earnings per common share if the Company had recognized compensation expense for all options granted based upon the

F-16



estimated fair value on the grant date under the fair value methodology prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation" (in thousands except per share amounts):

 
  Year ended December 31,
   
 
 
  Six months ended
June 30, 2005

 
 
  2003
  2004
  2005
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)
(unaudited)

 
Net income (loss) as reported   $ 2,714   $ 46,276   $ 16,110   $ 1,962  
  Add: Stock-based compensation expense included in the income statement, net of related tax effects                  
  Less: Total stock based compensation expense determined under the fair value method for all awards, net of related tax effects     (62 )   (62 )   (2,300 )   (1,320 )
   
 
 
 
 
  Pro forma net income (loss)   $ 2,652   $ 46,214   $ 13,810   $ 642  
   
 
 
 
 
Basic income (loss) per share:                          
  As reported   $ 0.07   $ 1.33   $ 0.49   $ 0.06  
  Pro forma   $ 0.06   $ 1.33   $ 0.42   $ 0.02  
Diluted income (loss) per share:                          
  As reported   $ 0.07   $ 0.48   $ 0.49   $ 0.06  
  Pro forma   $ 0.06   $ 0.47   $ 0.42   $ 0.02  

        For purposes of the pro forma disclosures, the estimated fair values of the options are amortized to expense over the options' vesting periods.

        Reclassifications—Transportation revenues of $1,454,000 and $1,541,000 for the years ended December 31, 2004 and 2003 were reclassified from transportation expenses to other revenues in the Consolidated Statement of Operations to conform to the current year presentation. This reclassification had no impact on net income or stockholders' equity as previously reported.

    New Accounting Standards

        In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations ("FIN 47"). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The adoption of FIN 47 did not have any impact on the Company's financial statements because the Company does not have any conditional asset retirement obligations that it has not accrued for.

        In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, which replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in

F-17



Interim Financial Statements. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. APB Opinion No. 20 previously required that most voluntary changes in an accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. SFAS No. 154 now requires retrospective application of changes in an accounting principle to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The Statement is effective for fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 effective January 1, 2006 and the adoption could have a material impact on its financial position and results of operations if the Company has an accounting change.

        In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140 ("SFAS 155"). This statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"), and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities and resolves issues addressed in SFAS 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interest in Securitized Financial Assets." This Statement: (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation; (b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133; (c) establishes a requirement to evaluate beneficial interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation; (d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity's ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value of those instruments. The Company is required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although early adoption is permitted as of the beginning of an entity's fiscal year. The Company is evaluating the provisions of SFAS 155. The effects of adopting of SFAS 155 on the Company's financial statements are not known at this time.

3.    ACQUISITIONS AND SALES OF PROPERTIES

        TexCal Energy Acquisition.    On March 31, 2006, the Company acquired 100% of the members' interest in TexCal Energy (LP) LLC (the "TexCal Acquisition"), an independent exploration and production company with properties in Texas and California, for approximately $456.8 million in cash and related financing costs of $14.4 million. TexCal had proved reserves of 31.4 MMBOE as of December 31, 2005 according to a reserve report prepared by TexCal's independent engineers. TexCal's operations are located entirely onshore and are concentrated in the Gulf Coast region of Texas and in the Sacramento Basin in California. The Company financed the acquisition through loans advanced under a second amendment and restatement of its existing revolving credit facility and a new senior secured second lien term loan facility. The purchase price was allocated to assets and liabilities, adjusted for tax effects, based on their estimated fair values at the date of acquisition. The acquisition

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was accounted for using the purchase method of accounting and has been included in the consolidated financial statements of Venoco as of the date of the acquisition.

        The cash consideration paid for the TexCal Acquisition was preliminarily allocated as follows (in thousands):

 
  Purchase Price
Allocation

 
Current assets   $ 25,834  
Oil and natural gas properties     459,732  
Other non-current assets     1,018  
Current liabilities     (22,052 )
Long-term asset retirement obligations     (7,722 )
   
 
Cash consideration   $ 456,810  
   
 

        Union Island.    In December 2005, the Company purchased the Union Island pipeline, a 32-mile natural gas pipeline running from the Union Island field to a location near Pittsburg, California, for $6.1 million.

        Willows-Beehive.    In September 2005, the Company acquired a 100% working interest in the Willows-Beehive Bend Gas Field, a 100% working interest in the Bounde Creek Gas Field and a 65% working interest in the Arbuckle Field for an aggregate net price of $10.1 million in cash. The Company operates all of the fields, which are located in the Sacramento Basin in California.

        In January 2006, the Company sold 35% of the interests it acquired in the Willows-Beehive Bend and Bounde Creek gas fields for $3.0 million. No gain was recognized from the sale for financial reporting purposes. The Company applied the proceeds of the sale to reduce the capitalized cost of oil and natural gas properties.

        Big Mineral Creek.    In February 2005, the Company entered into a purchase and sale agreement to sell its interest in the Big Mineral Creek field ("BMC"), located in Grayson County, Texas. The sales price was $45 million, subject to adjustments that, among other things, gave economic effect to the transaction as of February 1, 2005. The closing of the transaction occurred on March 31, 2005. In order to facilitate a like-kind exchange of the Company's BMC property under Section 1031 of the Internal Revenue Code, the proceeds from the sale of $44.6 million were deposited with a qualified intermediary. The Company acquired qualified replacement properties of approximately $15.6 million prior to the 180 day deadline, which expired on September 27, 2005. Included in the Company's qualified replacement properties acquired was a portion of the Marquez Energy properties. The Company has deferred a portion of the gain on sale of the BMC property under the provisions of section 1031 of the Internal Revenue Code. However, since the qualified replacement property acquired is less than the proceeds from the sale of the BMC property, the Company recognized for tax purposes a gain on the sale of the BMC property of approximately $27.9 million and incurred an associated tax liability of $11.1 million. In accordance with its accounting policies, the Company did not recognize a gain on sale for financial reporting purposes, but applied the proceeds to reduce the

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capitalized cost of its oil and natural gas properties. At March 31, 2005, the Company had not recorded a gain on the sale of the BMC property, but applied the sales proceeds of $44.6 million to reduce the capitalized cost of oil and natural gas properties and recorded the cash received as restricted for investment in oil and natural gas properties.

        Patagonia.    In March 2004, the Company sold its subsidiary Venoco Patagonia, Ltd., a Bermuda corporation, for $0.2 million. The $0.2 million sales price was comprised of cash of $0.1 million and payment of liabilities of $0.1 million. The gain recognized on the sale of the subsidiary was immaterial to the financial statements of the Company.

        North and South Afton.    In February 2004, the Company sold its interest in the North and South Afton, California, gas properties for a net sales price of approximately $1.5 million. In accordance with its accounting policies, the Company did not recognize any gain or loss on the transaction, but applied the net sales proceeds to reduce the capitalized cost of its oil and natural gas properties.

4.    HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

        The Company utilizes swap, collar agreements and option contracts to hedge the effect of price changes on a portion of its future oil and natural gas production. The objective of the Company's hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also limit future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.

        The components of commodity derivative losses in the consolidated income statements are as follows (in thousands):

 
  Year ended December 31,
  Six Months Ended
June 30,

 
 
  2003
  2004
  2005
  2005
  2006
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

  (Successor)

  (Successor)

 
 
   
   
   
  (unaudited)

 
Realized commodity derivative (losses)   $ (10,272 ) $ (17,589 ) $ (22,870 ) $ (7,155 ) $ (12,789 )
   
 
 
 
 
 
Unrealized commodity derivative gains (losses):                                
  Change in fair value of derivatives that do not qualify for hedge accounting         1,539     (36,000 )   (28,436 )   (13,839 )
  Ineffective portion of derivatives qualifying for hedge accounting         (2,635 )   1,275     437     (1,138 )
   
 
 
 
 
 
  Total unrealized commodity derivative (losses)         (1,096 )   (34,725 )   (27,999 )   (14,977 )
   
 
 
 
 
 
Total realized and unrealized commodity derivative (losses)   $ (10,272 ) $ (18,685 ) $ (57,595 ) $ (35,154 ) $ (27,766 )
   
 
 
 
 
 

        The estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2004 and 2005 and June 30, 2006 are summarized below. The increase in the net derivative liability from December 31, 2004 to December 31, 2005 is primarily attributable to the effect

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of rising oil and natural gas prices, partially offset by cash settlements of derivatives during the period. The increase in the net derivative liability from December 31, 2005 to June 30, 2006 is primarily attributable to the effect of rising oil and natural gas prices and the addition of oil collars, partially offset by the effect of declining natural gas prices, and natural gas puts and collars and cash settlements of derivatives during the period (in thousands):

 
  December 31,
2004

  December 31,
2005

  June 30,
2006

 
 
  (Successor)

  (Successor)

  (Successor)
(unaudited)

 
Derivative assets:                    
  Oil derivative contracts   $ 6,775   $ 1,899   $ 1,185  
  Gas derivative contracts     3,380     1,561     12,964  
Derivative liabilities:                    
  Oil derivative contracts     (1,383 )   (26,540 )   (56,727 )
  Gas derivative contracts     (137 )   (11,849 )   (6,011 )
   
 
 
 
Net derivative asset (liability)   $ 8,635   $ (34,929 ) $ (48,589 )
   
 
 
 

        As of December 31, 2005, an unrealized derivative fair value loss of $21.8 million ($13.2 million after tax), related to cash flow hedges, was recorded in accumulated other comprehensive loss, and as of June 30, 2006, an unrealized derivative fair value loss of $23.5 million ($14.2 million after tax), related to cash flow hedges, was recorded in accumulated other comprehensive loss. Based on the estimated fair values of derivative contracts that qualify for cash flow hedge accounting at June 30, 2006, the Company expects to reclassify net losses of $11.2 million ($6.8 million after tax) out of accumulated other comprehensive loss into earnings during the next twelve months. However, actual gains or losses may vary materially based on actual prices at the contract settlement dates.

        Crude Oil Agreements.    As of June 30, 2006, the Company has entered into option, swap and collar agreements to receive average minimum and maximum New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices as summarized below. Location and quality differentials attributable to the Company's properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX crude oil price.

 
  Minimum
  Maximum
 
  Barrels/day
  Avg. Prices
  Barrels/day
  Avg. Prices
Crude oil hedges at June 30, 2006 for production:                    
  July 1 - December 31, 2006   10,500   $ 47.85   7,000   $ 59.86
  January 1 - December 31, 2007   7,313   $ 49.72   6,115   $ 71.58
  January 1 - December 31, 2008   4,950   $ 54.43   4,950   $ 75.38
  January 1 - December 31, 2009   4,580   $ 53.94   4,580   $ 76.78

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        Natural Gas Agreements.    As of June 30, 2006, the Company had entered into option, swap and collar agreements to receive average minimum and maximum PG&E Citygate prices as follows:

 
  Minimum
  Maximum
 
  MMBtu/Day
  Avg. Prices
  MMBtu/Day
  Avg. Prices
Natural gas hedges at June 30, 2006 for production:                    
  July 1 - December 31, 2006   27,000   $ 7.19   21,000   $ 10.71
  January 1 - December 31, 2007   21,000   $ 7.42   15,436   $ 11.46
  January 1 - December 31, 2008   13,500   $ 8.00   11,947   $ 12.24
  January 1 - December 31, 2009   9,500   $ 7.61   9,500   $ 12.10

        The Company entered into derivative contracts for options that contain provisions for the deferral of the payment or receipt of premiums until the period of production for which the derivative contract relates. Both the derivative and the net liability for the payment of premiums were recorded at their fair values at the inception of the derivative contracts. The premiums for the derivative contract options contain an implicit interest rate factor for the difference in the derivative's fair value at inception and the liability for payment of premiums. The Company recorded $4.1 million for the net derivative premiums payable at June 30, 2006 (including $2.2 million in accounts payable and accrued liabilities and $1.9 million in long-term liabilities), net of the discount which will be amortized into interest expense over the term of the related contracts.

        As of December 31, 2005 and June 30, 2006, the Company had entered into a forward sales contract with a gas purchaser under which it is obligated for physical delivery of specified volumes of gas with a floor price. As this contract provides for physical delivery of the gas, it is not considered a derivative because it has been designated as a normal sale. The transaction will be recorded in the financial statements when the associated delivery occurs. The Company has contracted for 2,000 Mcf per day at a floor price of $4.85 per Mcf for the period October 1, 2005 to December 31, 2006.

        In August 2006, the Company entered into two basis swap contracts to mitigate the risk of adverse price movements in 2007 and 2008 between the NYMEX natural gas price and PG&E Citygate index, which is the index on which the Company's Sacramento Basin natural gas sales are based. Each swap contract is for 10,000 MMbtus per day of natural gas production and requires monthly settlement. The calendar year 2007 contract calls for the Company to receive the NYMEX Last Day Settlement Price less $0.58 per MMbtu and pay the PG&E Citygate Natural Gas Index. The calendar year 2008 contract calls for the Company to receive the NYMEX Last Day Settlement Price less $0.32 and pay the PG&E Citygate Natural Gas Index.

        The Company entered into an interest rate swap transaction during the quarter ended June 30, 2006 to lock in its interest cost on $200 million of borrowings under the second lien term loan facility at a fixed rate of 9.9225%, including a 4.5% margin, through May 2008. The Company pays a fixed interest rate of 5.4225% and receives a floating interest rate based on the three-month LIBOR rate. Settlements are made quarterly beginning August 2006. The Company has not designated this interest rate swap as a hedge. The fair value of the interest rate swap of $202 at June 30, 2006 has been recorded in other assets with a corresponding credit for the unrealized gain to interest expense.

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5.    LONG-TERM DEBT

        As of the dates indicated, our long term debt consisted of the following (in thousands):

 
  December 31,
2004

  December 31,
2005

  June 30,
2006

 
  (Successor)

  (Successor)

  (Successor)
(unaudited)

Revolving credit agreement due March 2009   $   $ 20,000   $ 159,529
Second lien term loan due March 2011             350,000
8.75% senior notes due December 2011     149,043     149,180     149,248
Marquez Energy credit agreement, terminated in 2005     4,684        
5.79% mortgage on office building due January 2015     9,942     9,889    
   
 
 
  Total long-term debt     163,669     179,069     658,777
  Less: current portion of long-term debt     (127 )   (126 )  
   
 
 
  Long-term debt, net of current portion   $ 163,542   $ 178,943   $ 658,777
   
 
 

        Senior notes.    On December 20, 2004, the Company issued $150.0 million in 8.75% senior notes (the "senior notes") due December 2011. Interest on the senior notes is due each June 15 and December 15 beginning June 15, 2005. The senior notes are senior obligations and contain covenants that, among other things, limit the Company's ability to make investments, incur additional debt, issue preferred stock, create liens or sell assets. The senior notes were issued as unsecured obligations, but became secured equally and ratably with the second lien term loan on March 30, 2006.

        Proceeds from the sale of the senior notes were used to repay $98.7 million the Company had borrowed against its $102 million Senior Secured Facility (the "Senior Facility") obtained in November 2004. Initial proceeds of $100.7 million from borrowings under the Senior Facility in 2004 were used to purchase all of the mandatorily redeemable convertible preferred stock plus accrued dividends at a cost of $72 million and to repay outstanding borrowings of $27.3 million under the Company's former $150.0 million senior secured revolving/term credit facility entered into in November 2000. In December 2004, the amended and restated Senior Facility became a revolving credit agreement with no associated term loan facility ("revolving credit agreement"). At December 31, 2005, the revolving credit agreement had a borrowing base of $80 million, was secured by a first priority lien on substantially all of the Company's oil and natural gas properties and other assets, including the stock of all of the Company's subsidiaries, and was unconditionally guaranteed by each of the Company's subsidiaries other than Ellwood Pipeline, Inc. and 6267 Carpinteria Avenue, LLC. The collateral also secured the Company's obligations to hedging counterparties that were also lenders, or affiliates of lenders, under the revolving credit agreement. As of December 31, 2005, the Company had available borrowing capacity of $59.5 million (net of $0.5 million in outstanding letters of credit). The revolving credit agreement, which was due to mature on November 4, 2007, was amended and restated in connection with the TexCal Acquisition.

        TexCal Acquisition Financing.    The Company financed the TexCal Acquisition through loans advanced under a second amendment and restatement of the revolving credit agreement and a new senior secured second lien term loan facility. On March 30, 2006, the Company borrowed $350 million pursuant to the second lien term loan facility. The Company entered into the second amendment and

F-23



restatement of the revolving credit agreement on March 30, 2006. On March 31, 2006, the Company borrowed approximately $119.5 million under the amended revolving credit agreement to finance the remainder of the TexCal purchase price and related financing costs of approximately $14.4 million. The term loan facility was amended and restated as of April 28, 2006 and the revolving credit agreement was further amended on May 2, 2006. The following summarizes certain terms of the credit facilities as amended.

        The amended revolving credit facility has an aggregate maximum loan amount of $300 million and an initial borrowing base of $200 million. Principal on the second lien term loan facility is payable on March 30, 2011, and principal on the revolving credit facility is payable on March 30, 2009. Pursuant to mandatory prepayment provisions set forth in the credit facilities, substantially all of the proceeds of asset sales and additional borrowings (except for certain unsecured borrowings and additional borrowings under the revolving credit facility), and up to 50% of the proceeds of equity issuances, must be used to reduce amounts outstanding under one or both facilities. The Company may from time to time make optional prepayments on outstanding loans. Under the second lien term loan facility, optional prepayments made prior to March 30, 2008 are subject to a prepayment premium. The revolving credit facility is secured by a first priority lien on substantially all of the Company's assets and is guaranteed by each of its subsidiaries other than Ellwood Pipeline, Inc. The second lien term loan facility is secured by second priority liens on the same collateral as the revolving credit agreement. A collateral trust agreement has been entered into in order to provide, for the benefit of the holders of the senior notes, liens on the Company's property that are equal and ratable with the liens securing the second lien term loan facility. At such time as all liens securing outstanding indebtedness under the revolving credit agreement and the second lien term loan facility constitute "Permitted Liens" (as defined in the indenture governing the notes), the collateral trust agreement will be terminated and the senior notes will no longer be secured obligations, but will be effectively junior in right of payment to the indebtedness under the revolving credit facility and the second lien term loan facility to the extent of the value of the collateral securing those facilities.

        Loans made under the revolving credit agreement and the second lien term loan facility are designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Base Rate Loans under the revolving credit agreement bear interest at a floating rate equal to (i) the greater of Bank of Montreal's announced base rate and the overnight federal funds rate plus 0.50% plus (ii) a margin ranging from zero to 0.75%, based upon utilization. LIBO Rate Loans under the revolving credit agreement bear interest at (i) LIBOR plus (ii) a margin ranging from 1.50% to 2.25%, based upon utilization. A commitment fee ranging from 0.375% to 0.5% per annum is payable with respect to unused borrowing availability under the facility.

        Base Rate Loans under the second lien term loan facility bear interest at a floating rate equal to (i) the greater of the administrative agent's announced base rate and the overnight federal funds rate plus 0.50% plus (ii) a margin ranging from 3.00% to 3.50%. LIBO Rate Loans under the second lien term loan facility bear interest at (i) LIBOR plus (ii) a margin ranging from 4.00% to 4.50%. In each case, the applicable margin depends on the Company's consolidated leverage ratio and whether the Company has completed a public equity offering.

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        The revolving credit agreement and the second lien term loan facility contain customary representations, warranties, events of default, indemnities and covenants, including financial covenants that require the Company to maintain specified ratios of EBITDA to interest expense, current assets to current liabilities, debt to EBITDA and PV-10 to total debt. The Company was in compliance with all debt covenants as of December 31, 2005 and June 30, 2006.

        Marquez Energy Credit Agreement.    At December 31, 2004, Marquez Energy (which merged with the Company on March 21, 2005) had a $5.0 million revolving credit facility with a bank. Interest accrued at the bank's prime rate plus 1 percent. The agreement was collateralized by Marquez Energy's oil and natural gas properties and was guaranteed by Marquez Energy's principal shareholder and president. The Company repaid the outstanding borrowings of $3.2 million and terminated this facility on March 21, 2005.

        Mortgage.    On December 9, 2004, 6267 Carpinteria Avenue, LLC ("6267 Carpinteria"), a wholly-owned subsidiary of the Company, purchased an office building in Carpinteria, California for $14.2 million. The purchase was financed in part by a secured 5.79% $10 million promissory note due January 1, 2015. The promissory note provided for a monthly payment of $58,612 beginning February 1, 2005 and continuing through December 1, 2014. The balance of unpaid principal and all accrued but unpaid interest was due and payable on January 1, 2015. On March 22, 2006, the Company paid a dividend consisting of 100% of the membership interests in 6267 Carpinteria to its sole stockholder, a trust controlled by the Company's CEO. The obligation for the 5.79% mortgage on the office building owned by 6267 Carpinteria was transferred to the sole stockholder in connection with the dividend.

        Scheduled annual maturities of long-term debt were as follows at the dates indicated:

Year Ending December 31 (in thousands):

  December 31,
2005

  June 30,
2006

 
   
  (unaudited)

2006   $ 126   $
2007     20,134    
2008     142    
2009     151     159,529
2010     160    
2011 and after     158,356     499,248
   
 
    $ 179,069   $ 658,777
   
 

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6.    INCOME TAXES

        The Company accounts for income taxes under SFAS No. 109 "Accounting for Income Taxes". SFAS 109 is an asset and liability approach that requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company's consolidated financial statements or tax returns. The components of deferred tax assets and liabilities are as follows (in thousands):

 
  December 31,
 
  2004
  2005
 
  (Predecessor)

  (Successor)

Deferred income tax assets:            
  Accrued liabilities   $ 408   $ 786
  Unrealized hedging losses         22,070
  Bad debts         303
  State tax benefit     441     1,053
  Alternative minimum tax credits     4,910     12
  Net operating loss carryforwards     6    
  Other     418     175
   
 
      6,183     24,399
Deferred income tax liabilities:            
  Oil and natural gas properties     36,475     38,636
  Prepaid expenses     845     1,260
  Unrealized hedging gains     862    
   
 
      38,182     39,896
   
 
Net deferred income tax liabilities     31,999     15,497
   
 
Net current deferred tax asset     209     8,611
   
 
Noncurrent deferred tax liability   $ 32,208   $ 24,108
   
 

        The Company's provision for income taxes is composed of the following (in thousands):

 
  2003
  2004
  2005
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

 
Current:                    
  Federal   $ 2,878   $ 4,229   $ 9,700  
  State     960     1,250     3,300  
Deferred     4,038     10,609     (2,700 )
   
 
 
 
  Total provision for income taxes   $ 7,876   $ 16,088   $ 10,300  
   
 
 
 

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        A reconciliation of the Company's federal statutory rate (35% in 2005, 35% in 2004 and 34% in 2003) to the Company's effective income tax rate is as follows (in thousands):

 
  2003
  2004
  2005
 
 
  (Predecessor)

  (Predecessor)

  (Successor)

 
Income tax expense at federal statutory rate   $ 6,339   $ 13,506   $ 9,200  
State income taxes     875     1,791     1,300  
Other     662     791     (200 )
   
 
 
 
    $ 7,876   $ 16,088   $ 10,300  
   
 
 
 

7.    NOTES RECEIVABLE—EMPLOYEES

        Notes receivable—employees consists of amounts due from employees of the Company. The notes bear interest at 6 percent per annum. Certain notes will be forgiven after a period of employment ranging from three to six years. Those notes are being amortized and recognized as compensation expense over the term of the note. If an employee is terminated before the term of the note expires, the employee is obligated to pay the unamortized amount on the note. The Company has on occasion in the past forgiven the remaining unamortized amount on certain notes. If the Company forgives the remaining unamortized amount of the employee note, the amount forgiven is charged to compensation expense. The unamortized amount of employee notes receivable was $60,000 and $46,000 at December 31, 2005 and 2004, respectively. These employee notes receivable, net of the amount amortized to compensation expense, are included in other assets on the Company's consolidated balance sheet. The Company periodically reviews employee notes receivable for collectibility and has determined that no reserve for uncollectible notes is necessary.

8.    STOCK OPTION PLANS

        During 2005, the Company entered into non-qualified stock option agreements with certain employees and officers of the Company other than Mr. Marquez. Total options granted in 2005 and through June 30, 2006 were 4,253,663 with a weighted average exercise price of $7.58 ($6.00 to $20.00). The options vest over a four year period, with 20% vesting on the grant date and 20% vesting on each subsequent anniversary of the grant date. The options will become immediately vested following a change in control of the Company. The agreements with employee option holders generally provide that all of the holder's options will vest if the Company terminates the holder's employment, unless the termination is for specified types of misconduct. The agreements with director option holders provide that any unvested options will terminate when the director's service to the Company ceases.

        Options under a prior plan were previously granted to employees and non-employee directors. On December 22, 2004, the Company's CEO, Timothy Marquez, effected a "short form" merger pursuant to Delaware law, the effect of which was to retire 78,188 options for cash of $0.24 per share (the difference between the exercise price of $2.22 per share and the $2.46 per share merger consideration) and to terminate 325,327 options that were out of the money. The Company recorded $19,000 as compensation expense for the year ended December 31, 2004, representing the amount paid to retire

F-27



the options. The prior option plan was terminated as a result of the merger and the Company had no outstanding or exercisable stock options at December 31, 2004.

Share-Based Payments

        Prior to January 1, 2006, the Company accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Under APB Opinion No. 25, no compensation expense was recognized for stock options issued to employees if the grant price equaled or exceeded the market price on the date of the option grant. Effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 123 (Revised), "Share-Based Payment" ("SFAS 123(R)") using the modified prospective method. Under this method, compensation cost is recorded for all unvested stock options beginning in the period of adoption and prior period financial statements are not restated. Under the fair value recognition provisions of SFAS 123(R), stock-based compensation is measured at the grant date based on the value of the awards and the value is recognized on a straight-line basis over the requisite service period (usually the vesting period). SFAS 123(R) also requires the recognition of the equity component of deferred compensation as additional paid-in capital.

        In accordance with the provisions of SFAS 123(R), total stock-based compensation cost in the amount of $1.3 million was recorded as general and administrative expense for the six months ended June 30, 2006. SFAS 123(R) requires the Company to estimate forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. The cumulative adjustment from adopting SFAS 123(R) as of January 1, 2006 to include estimated forfeitures in the calculation was not material and had no impact on earnings per share.

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        The following summarizes the Company's stock option activity for the years ended December 31, 2003, 2004 and 2005 and the six months ended June 30, 2006:

 
  Year Ended December 31,
   
   
 
  Six Months Ended
June 30, 2006

 
  2003
  2004
  2005
 
  Shares
  Weighted
Average
Exercise
Price

  Shares
  Weighted
Average
Exercise
Price

  Shares
  Weighted
Average
Exercise
Price

  Shares
  Weighted
Average
Exercise
Price

 
   
   
   
   
   
   
  (unaudited)

Outstanding, start of period   744,773   $ 3.24   403,515   $ 3.48         4,013,663   $ 7.04
Granted                   4,013,663   $ 7.04   240,000     16.58
Exercised           (78,188 ) $ 2.22            
Cancelled   (341,258 ) $ 2.96   (325,327 ) $ 3.78            
   
 
 
 
 
 
 
 
Outstanding, end of period   403,515   $ 3.48         4,013,663   $ 7.04   4,253,663   $ 7.58
   
 
 
 
 
 
 
 
Exercisable, end of period   267,966   $ 3.73         802,732   $ 7.04   1,561,965   $ 7.58
Weighted average grant-date fair value of options granted during the period       $       $       $ 2.78       $ 5.79

        Additional information related to options outstanding at June 30, 2006 is as follows (unaudited):

 
  Options Outstanding
  Options Exercisable
Range of
Exercise
Prices

  Number
Outstanding

  Weighted
Average
Remaining
Contractual
Life

  Weighted-
Average
Exercise
Prices

  Number
Exercisable

  Weighted
Average
Exercise
Prices

$6.00–$7.33   2,995,200   8.7 years   $ 6.12   1,198,080   $ 6.12
$8.00–$8.68   560,963   8.8 years   $ 8.33   224,385   $ 8.33
$10.67–$13.33   497,500   9.2 years   $ 11.53   99,500   $ 11.53
$15.00–$20.00   200,000   9.7 years   $ 17.50   40,000   $ 17.50
   
           
     
    4,253,663   8.8 years   $ 7.58   1,561,965   $ 7.58
   
           
     

        The fair value of each option is estimated on the grant date using the Black-Scholes option valuation model. Option valuation models require the input of highly subjective assumptions, including the expected volatility of the price of the underlying stock. The Company's stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management's opinion that the valuations afforded by the existing models are different from the value that the options would realize if traded in the market.

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        The following assumptions were used during 2005 and the six months ended June 30, 2005 and 2006 to compute the weighted average fair market value of options granted during the periods presented:

 
   
  Six Months Ended
June 30,

 
 
  Year Ended
December 31,
2005

 
 
  2005
  2006
 
 
   
  (unaudited)

 
Expected option life   5 years   5 years   7 years  
Risk free interest rates   3.7%-4.2 % 3.89 % 4.32 %
Estimated volatility   76 % 76 % 61 %
Dividend yield   0.0 % 0.0 % 0.0 %

        The expected life of the options is based, in part, on historical exercise patterns of the holders of options with similar terms with consideration given to how historical patterns may differ from future exercise patterns based on current or expected market conditions and employee turnover. On January 1, 2006, the Company began calculating the expected life of options granted using the "simplified method' set forth in Staff Accounting Bulletin 107 (average of vesting period and the term of the option). The risk free interest rate was based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility was based on the historical volatility of other public companies with characteristics similar to the company for the past five years.

        As of June 30, 2006, there was $6.2 million of total unrecognized compensation cost related to stock options which is expected to be amortized over a weighted-average period of 2.7 years.

9.    COMMITMENTS AND CONTINGENCIES

        Leases—The Company has entered into agreements to lease office space from third parties. As of December 31, 2005, future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are $191,000, $190,000 and $65,000 in 2006, 2007 and 2008, respectively. Net rent expense incurred on office space leased from third parties was $1.0 million, $1.2 million and $0.9 million in 2003, 2004 and 2005, respectively.

10.    401(k) PLAN

        The Company has established a qualified cash or deferred arrangement under Internal Revenue Code Section 401(k) covering substantially all employees. Under the plan, the employees may elect to contribute a portion of their eligible compensation, not to exceed specified annual limitations, to the plan and the Company may elect to match a percentage of the employee's contribution. The Company made matching contributions to the plan totaling $0.4 million, $0.4 million, and $0.7 million in 2003, 2004, and 2005, respectively.

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11.    PREFERRED STOCK AND SHAREHOLDERS' EQUITY

        The Company issued 6,000 shares of mandatorily redeemable convertible non-participating preferred stock in 1998 for $10,000 per share. The shares were mandatorily redeemable in 2009 at $10,000 per share and accrued dividends at an 8 percent annual cash dividend rate, payable quarterly. In November 2004, the Company repurchased all of the outstanding preferred stock, consisting of 6,000 shares of preferred stock plus accrued and unpaid dividends, for $72 million. At the time of the purchase of the preferred stock, the Company had recorded preferred stock and accrued but unpaid dividends net of unamortized issuance costs of $101.9 million. Additional paid-in capital was increased by the excess of the carrying value of the preferred stock over the repurchase price of $29.9 million.

        On January 3, 2005, a dividend of $35 million was paid to the Company's sole stockholder, a trust controlled by the Company's CEO, from the proceeds of the issuance of the senior notes.

        On March 22, 2006, the Company paid a dividend consisting of 100% of its membership interest in 6267 Carpinteria to its sole stockholder, a trust controlled by the Company's CEO. 6267 Carpinteria owns the office building and related land used by the Company in Carpinteria, California. At the date of the dividend, 6267 Carpinteria had net assets of $4.7 million, including $0.4 million in cash and land and building with a net book value of $13.4 million, and a note payable of $9.9 million.

12.    LITIGATION

Beverly Hills Litigation

        Eight lawsuits have been filed by persons who are graduates of the Beverly Hills High School or citizens of Beverly Hills/Century City or visitors to that area from the time period running from the 1930s to date. Six of these lawsuits name the Company as a defendant. There are approximately 1,000 plaintiffs who claim they are suffering from various forms of cancer or some other medical ailment, fear they may suffer from such maladies in the future, or are related in some manner to someone that suffered from cancer (e.g. heirs or spouses). Plaintiffs' claims are based on alleged exposure to levels of some substances in the air, soil and water which derive from either oil field or other operations in the area. The Company has owned an oil and natural gas facility adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before the Company owned the facility. It is anticipated that additional plaintiffs may be added to the litigation over time. The Company has defense and indemnity obligations to certain other defendants in the actions. Management believes that the claims made in the suits are without merit and the Company intends to defend against the claims vigorously. However, the Company cannot predict, at this time, the outcome of the suits. All cases are consolidated before one judge. The judge has ordered that all of the cases be stayed except for a test case consisting of twelve plaintiffs. The trial date for the twelve "test" plaintiffs has been moved to October 2006.

        One of the Company's insurers is currently paying for the defense of these lawsuits under a reservation of its rights. Two other insurers that provided insurance coverage to the Company (the "Declining Insurers") have taken the position that they are not required to provide coverage relating to the lawsuits because of a pollution exclusion contained in their policies. The Beverly Hills School District (the "District"), as an additional insured on those policies, brought a declaratory relief action against those insurers in Los Angeles County Superior Court. In November 2005, the court ruled in favor of one of the insurers. The District is appealing that decision. On July 10, 2006, the same Los

F-31



Angeles County Superior Court denied a motion for summary judgment by another of the insurers against the District on the issue of the duty to defend. On February 10, 2006, the Company filed its own declaratory relief action against the Declining Insurers in Santa Barbara County Superior Court seeking a determination that those insurers have a duty to defend the Company in the lawsuits. The policy issued by the insurer that is currently providing defense of the lawsuits contains a pollution exclusion similar to that at issue in the action brought by the District. However, the Company has no reason to believe that the insurer currently providing defense of these actions will cease providing such defense. If it does, and the Company is unsuccessful in enforcing its rights in any subsequent litigation, the Company may be required to bear the costs of the defense, and those costs may be material. If it is ultimately determined that the pollution exclusion or another exclusion contained in one or more of the Company's policies applies, the Company will not have the protection of those policies with respect to any damages or settlement costs ultimately incurred in the lawsuits.

        The Company cannot predict the cost of defense and indemnity obligations, if any, at the present time. In accordance with SFAS No. 5, Accounting for Contingencies, the Company has not accrued for a loss contingency relating to the Beverly Hills litigation because it believes that, although unfavorable outcomes in the proceedings may be possible, they are not considered by management to be probable or reasonably estimable. If one or more of these matters are resolved in a manner adverse to the Company, and if insurance coverage is determined to not be applicable, their impact on the Company's results of operations, financial position and/or liquidity could be material.

Personal Injury Claims

        On February 23, 2006, a complaint was filed in Santa Barbara Superior Court against the Company on behalf of a boy who was severely injured after falling from a cliff located on property jointly owned by the Company and another company. The complaint asserts that the Company is responsible for the boy's injuries and that the boy is entitled to damages, including reimbursement of past medical expenses, future expenses, loss of earning capacity and general damages. The Company believes that it has no liability in this matter and intends to defend itself vigorously. In accordance with SFAS No. 5, Accounting for Contingencies, the Company has not accrued for a loss contingency related to this claim because it believes that, although an unfavorable outcome may be possible, such an outcome is not considered by management to be probable.

        On March 31, 2006, a complaint was filed in District Court in Madison County, Texas against a subsidiary of the Company by the widow of an individual who was fatally injured while working as a gauger/pumper at a well operated by the subsidiary. The cause of the accident is still being investigated. The Company believes that it has insurance coverage with respect to the accident.

Litigation by former directors and former preferred stockholders

        In December 2004, a lawsuit was filed against the Company by two of its former directors and the former preferred shareholders. The claim was for indemnification of attorneys' fees and expenses incurred in defending the former directors in litigation filed by the former CEO in connection with the termination of his employment from the Company. At December 31, 2004, the Company accrued

F-32



$750,000 with respect to this matter in accordance with SFAS No. 5, Accounting for Contingencies. The Company settled this litigation for $700,000 in July 2005. The case was dismissed in August 2005.

Former Chief Operating Officer (COO) Litigation and Appraisal Request

        In December 2004, a former COO of the Company filed a lawsuit against the Company and its CEO in Santa Barbara County Superior Court, claiming that the Company breached his employment agreement and wrongfully failed to pay him wages due, primarily in connection with stock bonuses. In April 2005, the former COO, in connection with the merger effected on December 22, 2004 and described in Note 1, filed a Petition for Appraisal in the Delaware Court of Chancery requesting an appraisal of the shares he held, as well as those shares which were the subject of the employment agreement dispute. The Company accrued $56,000 in compensation costs with respect to these matters as of December 31, 2004, which is the amount it believed represented the amount due under the agreement. In August 2005, the Company and the former COO agreed to settle the lawsuit for amounts accrued in the financial statements and the actions filed were dismissed.

Related Party Litigation

        In 2002, the Chief Executive Officer ("CEO") of the Company was terminated by the Board of Directors and subsequently filed a wrongful termination/breach of contract lawsuit and a shareholder derivative action against the Company and its directors. The Company asserted a cross-complaint for enforcement of a written promissory note made by the CEO to the Company. On February 23, 2004, the Company reached a settlement to resolve all litigation with the former CEO. As part of the settlement, the Company made a payment of $0.3 million to the former CEO and he agreed to repay the promissory note. The Company subsequently cancelled the promissory note totaling $1.4 million (notes receivable—officers at December 31, 2004) and the former CEO issued a new note in the same amount to Marquez Energy (the "Purchaser"), an affiliate of the former CEO, as described further below.

        Also on February 23, 2004, as part of the settlement with the former CEO, the Company entered into a Purchase and Sale Agreement (PSA) with the Purchaser to sell the Company's Willows and Grimes, California, gas properties effective February 1, 2004 for a cash consideration of $13.8 million, reduced by the operating results from the properties through the close of the sale. Both the Company and the Purchaser believed the fair value of the gas properties to be higher than $13.8 million. The Company did not meet certain conditions to close the sale by May 24, 2004 as was required under the terms of the PSA and was therefore required to pay a $4.5 million termination fee to the Purchaser, of which $3.1 million was paid in cash and $1.4 million in the form of the issuance to the Purchaser of a note in that amount by the former CEO and the related cancellation of the former CEO's note to the Company. Additionally, the Company was required to pay an additional fee of $0.7 million related to the sale. The settlement cost, termination fee and the additional fee are included in accrued liabilities and have been expensed in the accompanying consolidated financial statements for the year 2003. Following the May 24, 2004 payments the Purchaser had the option of depositing, in escrow, $1.5 million to effectively extend the closing date to August 20, 2004. In May 2004, the Purchaser notified the Company of its intention to exercise its option to extend the closing date.

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        On August 17, 2004, as part of the settlement with the former CEO, the Company and Purchaser entered into a Memorandum of Settlement pursuant to which Purchaser relinquished all of its rights to acquire the Willows and Grimes properties in return for a cash payment of $0.5 million, plus the right to participate in the development of future reserves, other than currently identified proved reserves, in the Willows and Grimes fields. The settlement payment of $0.5 million is included in accrued liabilities and has been expensed in the accompanying consolidated financial statements for the year 2003.

Other

        In addition, the Company is subject to other claims and legal actions that may arise in the ordinary course of business. The Company believes that the ultimate liability, if any, with respect to these other claims and legal actions will not have a material effect on the Company's consolidated financial position, results of operations or liquidity.

13.    ASSET RETIREMENT OBLIGATIONS

        The Company's asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing properties (including removal of certain onshore and offshore facilities in California) at the end of their productive lives in accordance with applicable state and federal laws.

        Prior to January 1, 2003, the Company recognized the cost to abandon its oil and natural gas properties over their productive lives on a unit-of-production basis. Effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with a corresponding increase in the carrying amount of the related long lived asset. Upon adoption of SFAS No. 143 in the first quarter of 2003, the Company recorded a $12.4 million increase in oil and natural gas properties, a net decrease of $6.9 million in accumulated depletion, depreciation and amortization expense, an asset retirement obligation of $18.6 million, and recognized an after-tax gain of $0.4 million representing the cumulative effect of the change in accounting principle. Subsequent to initial measurement, the Company determines asset retirement obligations by calculating the present value of estimated cash flows related to plug and abandonment liabilities. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted over the productive life of the related assets. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or decrease in the asset retirement obligation and the related capitalized asset retirement costs. Capitalized costs are depleted as a component of the full cost pool using the units-of production method.

F-34


        The following table summarizes the activities for the Company's asset retirement obligations for the years ended December 31, 2004 and 2005 and the six months ended June 30, 2006 (in thousands):

 
  2004
  2005
  June 30,
2006

 
 
  (Successor)

  (Successor)

  (Successor)
(unaudited)

 
Asset retirement obligations at beginning of period   $ 19,248   $ 23,390   $ 22,757  
Revisions of estimated liabilities     1,914     (3,083 )   2,594  
Liabilities incurred     865     1,267     9,517  
Liabilities settled     (119 )   (569 )   (5 )
Accretion expense     1,482     1,752     1,111  
   
 
 
 
  Asset retirement obligations at end of period     23,390     22,757     35,974  
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)     (206 )   (108 )   (1,556 )
   
 
 
 
  Long-term asset retirement obligations   $ 23,184   $ 22,649   $ 34,418  
   
 
 
 

        Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 6% and 8%. The 2004 revisions of estimated liabilities primarily relate to an updated MMS study for abandonment costs for offshore platforms. The 2005 revisions primarily relate to extensions in the timing of obligations based on reserve evaluations. Liabilities incurred in the six months ended June 30, 2006 include $8.9 million of asset retirement obligations attributable to the acquisition of TexCal.

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14.    QUARTERLY FINANCIAL DATA (UNAUDITED)

        The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2004 and 2005 (in thousands except per share data):

 
  Three Months Ended
 
 
  March 31,
2004

  June 30,
2004

  September 30,
2004

  December 31,
2004

 
Year Ended December 31, 2004:                          
  Revenues   $ 29,102   $ 29,047   $ 32,978   $ 35,606  
  Net income (loss) attributable to common stock     3,663     3,412     4,830     34,371  
  Add: Preferred stock dividend     2,116     2,116     2,116     786  
  Deduct: Excess carrying value over repurchase price of preferred stock                 (29,904 )
   
 
 
 
 
  Net income adjusted for effect of dilution   $ 5,779   $ 5,528   $ 6,946   $ 5,253  
   
 
 
 
 
  Basic earnings per common share   $ 0.10   $ 0.10   $ 0.14   $ 1.09  
  Diluted earnings per common share   $ 0.10   $ 0.10   $ 0.13   $ 0.14  
 
  Three Months Ended
 
  March 31,
2005

  June 30,
2005

  September 30,
2005

  December 31,
2005

Year Ended December 31, 2005:                        
  Revenues   $ 13,957   $ 40,370   $ 23,525   $ 60,101
  Net income (loss)   $ (6,818 ) $ 8,780   $ (1,833 ) $ 15,981
  Basic earnings (loss) per common share   $ (0.21 ) $ 0.27   $ (0.06 ) $ 0.49
  Diluted earnings (loss) per common share   $ (0.21 ) $ 0.27   $ (0.06 ) $ 0.48

        Operating results for the quarter ended December 31, 2005 improved compared to prior quarters in 2005 due to unrealized hedging gains on derivative contracts and slightly improved oil and natural gas prices realized. The Company recorded net unrealized gains on derivative contracts of $9.5 million for the quarter ended December 31, 2005 vs. unrealized losses on derivative contracts of $44.2 million for nine months ended September 30, 2005. Future operating results may continue to fluctuate because of the effects that changing commodity prices have on unrealized gains and losses on derivative contracts. In addition, average sales prices per BOE, net of realized hedging losses, were $46.38 for the quarter ended December 31, 2005 vs. average sales prices per BOE of $37.24 for the nine months ended September 30, 2005.

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15.    SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

        The following information concerning the Company's natural gas and oil operations has been provided pursuant to Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities. At December 31, 2005, the Company's oil and natural gas producing activities were conducted onshore within the continental United States and offshore in federal and state waters off the coast of California. The evaluations of the oil and natural gas reserves at December 31, 2005 and 2004 were estimated by independent petroleum reserve engineers, Netherland, Sewell & Associates, Inc. The evaluations of the oil and natural gas reserves as of December 31, 2003 were estimated by independent petroleum reserve engineers, Ryder Scott Company, L.P. The following does not include information relating to Marquez Energy for 2004, which is not material.

Capitalized Costs of Oil and Natural Gas Properties

 
  As of December 31,
 
 
  2003
  2004
  2005
 
 
  (in thousands)

 
Properties not subject to amortization:                    
  Unevaluated costs(1)   $ 6,764   $ 384   $ 2,275  
  Deposit for purchase of Marquez Energy, LLC(2)         2,000      
   
 
 
 
      6,764     2,384 (3)   2,275  
Properties subject to amortization     241,608     205,134     267,647  
   
 
 
 
Total capitalized costs     248,372     207,518     269,922  
Accumulated depreciation, depletion and amortization     (89,603 )   (45,626 )   (66,218 )
   
 
 
 
Net capitalized costs   $ 158,769   $ 161,892   $ 203,704  
   
 
 
 

(1)
Unevaluated costs represent amounts the Company excludes from the amortization base until proved reserves are established or impairment is determined. The Company estimates that the remaining costs will be evaluated within one year.

(2)
Amount relates to a deposit made by the Company to the selling members of Marquez Energy in connection with the acquisition of Marquez Energy.

(3)
The supplemental information does not include Marquez Energy in 2004. The amount disclosed on the face of the balance sheet (see page F-3 for properties not subject to amortization) does include unproved capital costs from Marquez Energy of $933.

Capitalized Costs Incurred

        Costs incurred for oil and natural gas exploration, development and acquisition are summarized below. Costs incurred during the years ended December 31, 2003, 2004 and 2005 include capitalized interest expense and general and administrative costs related to acquisition, exploration and

F-37



development of natural gas and oil properties of $3.5 million, $2.7 million and $2.5 million, respectively. Costs incurred also include asset retirement costs incurred of $12.4 million, $1.9 million and $1.3 million during the years ended December 31, 2003, 2004 and 2005, respectively. Asset retirement costs incurred in 2003 include $12.4 million related to the adoption of SFAS No. 143 on January 1, 2003.

 
  For the year ended December 31,
 
  2003
  2004
  2005
 
  (in thousands)

Property acquisition and leasehold costs                  
  Unevaluated property   $ 633   $ 129   $ 1,891
  Deposit for purchase of Marquez Energy         2,000    
  Proved property     115     165     10,636
Exploration costs     1,291     2,213     20,592
Development costs     19,422     20,634     62,082
   
 
 
Total costs incurred   $ 21,461   $ 25,141   $ 95,201
   
 
 

Estimated Net Quantities of Natural Gas and Oil Reserves

        The following table sets forth the Company's net proved reserves, including changes, and proved developed reserves (all within the United States) at the end of each of the three years in the periods ended December 31, 2003, 2004 and 2005.

 
  Crude Oil, Liquids and Condensate
(MBbls)

  Natural Gas
(MMcf)

 
 
  2003
  2004
  2005
  2003
  2004
  2005
 
Beginning of the year reserves   56,112   46,757   39,935   73,428   66,585   69,876  
Revisions of previous estimates   (6,964 ) (7,357 ) (318 ) (3,185 ) (9,090 ) (6,083 )
Extensions, discoveries and improved recovery   723   3,636   1,580   1,949   18,638   7,240  
Purchases of reserves in place       2       13,390  
Production   (3,114 ) (3,101 ) (2,953 ) (5,607 ) (5,366 ) (7,588 )
Sales of reserves in place       (2,946 )   (891 ) (2,782 )
   
 
 
 
 
 
 
End of year reserves   46,757   39,935   35,300   66,585   69,876   74,053  
   
 
 
 
 
 
 
Proved developed reserves:                          
Beginning of year   34,782   31,423   28,035   53,687   51,112   49,418  
End of year   31,423   28,035   24,154   51,112   49,418   53,390  

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        The Company's estimated proved reserves at year-end December 31, 2005 were approximately 3.9 MMBOE lower than at December 31, 2004. The reduction was due primarily to the Company's sale of the Big Mineral Creek property (partially offset by net reserve acquisitions during the year), depletion that occurred as a result of production and other adjustments based on reservoir information.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

        The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by the Statement of Financial Accounting Standards No. 69, is an attempt to present the information in a manner comparable with industry peers.

        The information is based on estimates of proved reserves attributable to the Company's interest in oil and natural gas properties as of December 31 of the years presented. These estimates were prepared by independent petroleum engineers. Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

        The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

    (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.

    (2) The estimated future cash flows are compiled by applying year-end prices of crude oil and natural gas relating to the Company's proved reserves to the year-end quantities of those reserves.

    (3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions.

    (4) Future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company's proved oil and natural gas reserves.

    (5) Future net cash flows are discounted to present value by applying a discount rate of 10%.

        The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

F-39


        The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows and does not include cash flows associated with hedges outstanding at each of the respective reporting dates.

 
  As of December 31,
 
 
  2003
  2004
  2005
 
 
  (in thousands)

 
Future cash inflows   $ 1,594,980   $ 1,982,599   $ 2,456,617  
Future production costs     (811,821 )   (826,527 )   (876,858 )
Future development costs     (103,218 )   (146,096 )   (163,476 )
Future income taxes     (234,777 )   (376,618 )   (516,416 )
   
 
 
 
Future net cash flows     445,164     633,358     899,867  
10% annual discount for estimated timing of cash flows     (186,687 )   (229,306 )   (334,482 )
   
 
 
 
Standardized measure of discounted future net cash flows   $ 258,477   $ 404,052   $ 565,385  
   
 
 
 

        The following table summarizes changes in the standardized measure of discounted future net cash flows.

 
  As of December 31,
 
 
  2003
  2004
  2005
 
 
  (in thousands)

 
Beginning of the year   $ 322,981   $ 258,477   $ 404,052  
Revisions to previous estimates:                    
Changes in prices and production costs     (60,766 )   298,394     332,940  
Revisions of previous quantity estimates     (53,586 )   (115,876 )   (28,544 )
Changes in future development costs     7,894     (32,472 )   (54,784 )
Development costs incurred during the period     6,993     18,734     61,404  
Extensions, discoveries and improved recovery, net of related costs     7,492     88,056     59,733  
Sales of oil and natural gas, net of production costs     (62,842 )   (86,752 )   (137,054 )
Accretion of discount     48,394     39,658     65,308  
Net change in income taxes     22,848     (110,920 )   (79,418 )
Sale of reserves in place         (1,317 )   (73,081 )
Purchases of reserves in place             47,046  
Production timing and other     19,069     48,070     (32,217 )
   
 
 
 
End of year   $ 258,477   $ 404,052   $ 565,385  
   
 
 
 

F-40


16.    GUARANTOR FINANCIAL INFORMATION

        In connection with the issuance of the senior notes in December 2004, BMC, Ltd., Whittier Pipeline Corp. and 217 State Street, Inc. ("Guarantors") fully and unconditionally guaranteed, on a joint and several basis, the Company's obligations under the senior notes. On March 31, 2005, Marquez Energy became a Guarantor of the senior notes. The Company had two subsidiaries, 6267 Carpinteria and Ellwood Pipeline, Inc., that have not been Guarantors, and 6267 Carpinteria ceased being a subsidiary on March 22, 2006 (the "Non-Guarantor Subsidiaries"). On November 1, 2005, the Company merged Marquez Energy and 217 State Street with and into Venoco, Inc., leaving BMC and Whittier as the only Guarantors until the TexCal Acquisition. On March 31, 2006, TexCal and its four subsidiaries became Guarantors. All Guarantors are 100% owned by the Company.

        The following are condensed consolidating statements of operations for the Company for the years ended December 31, 2003, 2004 and 2005 and the six months ended June 30, 2005 and 2006; condensed consolidating balance sheets as of December 31, 2004 and 2005 and June 30, 2006; and condensed consolidating statements of cash flows for the years ended December 31, 2003, 2004 and 2005 and the six months ended June 30, 2005 and 2006. The condensed consolidating financial information for 2003 and 2004 has been revised to reflect the guarantor and non-guarantor status of the Company's subsidiaries at December 31, 2005.

F-41




CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS—

YEAR ENDED DECEMBER 31, 2003 (Predecessor)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
REVENUES:                                
  Oil and natural gas   $ 102,642   $ 7,112   $   $   $ 109,754  
  Commodity derivative losses—realized     (10,272 )               (10,272 )
  Commodity derivative losses—unrealized                      
  Other     3,980         5,868     (4,595 )   5,253  
   
 
 
 
 
 
    Total revenues     96,350     7,112     5,868     (4,595 )   104,735  
   
 
 
 
 
 
EXPENSES:                                
  Oil and natural gas production     42,650     1,928     1,039         45,617  
  Transportation expense     7,115             (4,330 )   2,785  
  Depletion, depreciation, amortization and impairment     14,670     818     673         16,161  
  Accretion of abandonment liability     1,322     68     11         1,401  
  General and administrative, net of amounts capitalized     10,931     670     296     (265 )   11,632  
  Litigation settlement     6,000                 6,000  
  Amortization of deferred loan costs     370                 370  
  Interest, net     3,124         (999 )       2,125  
   
 
 
 
 
 
    Total expenses     86,182     3,484     1,020     (4,595 )   86,091  
   
 
 
 
 
 
Equity in subsidiary income     4,726             (4,726 )    
   
 
 
 
 
 
Income before income taxes and cumulative effect of change in accounting principle     14,894     3,628     4,848     (4,726 )   18,644  
Income tax expense     4,295     1,533     2,048         7,876  
   
 
 
 
 
 
Net income before cumulative effect of change in accounting principle     10,599     2,095     2,800     (4,726 )   10,768  
   
 
 
 
 
 
Cumulative effect of change in accounting principle, net of tax     580     (169 )           411  
   
 
 
 
 
 
Net income   $ 11,179   $ 1,926   $ 2,800   $ (4,726 ) $ 11,179  
   
 
 
 
 
 

F-42



CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS—

YEAR ENDED DECEMBER 31, 2004 (Predecessor)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
REVENUES:                                
  Oil and natural gas   $ 131,263   $ 8,698   $   $   $ 139,961  
  Commodity derivative losses—realized     (17,589 )               (17,589 )
  Commodity derivative losses—unrealized     (1,096 )               (1,096 )
  Other     4,079     58     5,946     (4,626 )   5,457  
   
 
 
 
 
 
    Total revenues     116,657     8,756     5,946     (4,626 )   126,733  
   
 
 
 
 
 
EXPENSES:                                
  Oil and natural gas production     46,027     2,031     1,509         49,567  
  Transportation expense     7,285             (4,370 )   2,915  
  Depletion, depreciation, amortization and impairment     15,529     787     173         16,489  
  Accretion of abandonment liability     1,389     71     22         1,482  
  General and administrative, net of amounts capitalized     10,685     630     213     (256 )   11,272  
  Amortization of deferred loan costs     3,050                 3,050  
  Interest, net     3,663         (1,394 )       2,269  
   
 
 
 
 
 
    Total expenses     87,628     3,519     523     (4,626 )   87,044  
   
 
 
 
 
 
Equity in subsidiary income     6,216             (6,216 )    
   
 
 
 
 
 
Income before income taxes     35,245     5,237     5,423     (6,216 )   39,689  
Income tax expense     11,644     2,246     2,198         16,088  
   
 
 
 
 
 
Income before minority interest in Marquez Energy     23,601     2,991     3,225     (6,216 )   23,601  
Minority interest in Marquez Energy     95                 95  
   
 
 
 
 
 
Net income   $ 23,506   $ 2,991   $ 3,225   $ (6,216 ) $ 23,506  
   
 
 
 
 
 

F-43



CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS—

YEAR ENDED DECEMBER 31, 2005 (Successor)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
REVENUES:                                
  Oil and natural gas sales   $ 186,130   $ 4,962   $   $   $ 191,092  
  Commodity derivative losses—realized     (22,870 )               (22,870 )
  Commodity derivative losses—unrealized     (34,725 )               (34,725 )
  Other     3,283     21,670     7,110     (27,607 )   4,456  
   
 
 
 
 
 
    Total revenues     131,818     26,632     7,110     (27,607 )   137,953  
   
 
 
 
 
 
EXPENSES:                                
  Oil and natural gas production     51,751     547     1,740         54,038  
  Transportation expense     6,817             (4,221 )   2,596  
  Depletion, depreciation, amortization and impairment     21,070     313     297         21,680  
  Accretion of abandonment liability     1,663     67     22         1,752  
  General and administrative, net of amounts capitalized     16,950     125     654     (1,722 )   16,007  
  Amortization of deferred loan costs     15,621     (665 )   (1,283 )       13,673  
  Interest, net     1,755                 1,755  
   
 
 
 
 
 
    Total expenses     115,627     387     1,430     (5,943 )   111,501  
   
 
 
 
 
 
Equity in subsidiary income     5,987             (5,987 )    
   
 
 
 
 
 
Income before income taxes     22,178     26,245     5,680     (27,651 )   26,452  
Income tax provision (benefit)     6,026     10,221     2,211     (8,158 )   10,300  
   
 
 
 
 
 
Income before minority interest     16,152     16,024     3,469     (19,493 )   16,152  
Minority interest in Marquez Energy     (42 )               (42 )
   
 
 
 
 
 
Net income   $ 16,110   $ 16,024   $ 3,469   $ (19,493 ) $ 16,110  
   
 
 
 
 
 

F-44



CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2005 (Successor) (Unaudited)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-
Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
REVENUES:                                
  Oil and natural gas sales   $ 84,704   $ 2,686   $   $   $ 87,390  
  Commodity derivative losses (realized)     (7,155 )               (7,155 )
  Commodity derivative losses (unrealized)     (27,999 )               (27,999 )
  Other     1,692     21,670     3,742     (25,013 )   2,091  
   
 
 
 
 
 
    Total revenues     51,242     24,356     3,742     (25,013 )   54,327  
   
 
 
 
 
 
EXPENSES:                                
  Oil and natural gas production     23,138     477     667         24,282  
  Transportation expense     3,833     (141 )       (2,476 )   1,216  
  Depletion, depreciation and amortization     9,083     254     156         9,493  
  Accretion of abandonment liability     969     38     11         1,018  
  General and administrative, net of amounts capitalized     8,427     124     287     (1,139 )   7,699  
  Amortization of deferred loan costs     1,021                 1,021  
  Interest, net     7,403         (583 )       6,820  
   
 
 
 
 
 
    Total expenses     53,874     752     538     (3,615 )   51,549  
   
 
 
 
 
 
Equity in subsidiary income     4,102             (4,102 )    
   
 
 
 
 
 
Income before income taxes     1,470     23,604     3,204     (25,500 )   2,778  
Income tax provision (benefit)     (534 )   9,902     1,303     (9,897 )   774  
   
 
 
 
 
 
Income before minority interest in Marquez Energy     2,004     13,702     1,901     (15,603 )   2,004  
Minority interest in Marquez Energy     42                 42  
   
 
 
 
 
 
Net income   $ 1,962   $ 13,702   $ 1,901   $ (15,603 ) $ 1,962  
   
 
 
 
 
 

F-45



CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2006 (Successor) (Unaudited)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-
Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
REVENUES:                                
  Oil and natural gas sales   $ 100,931   $ 26,443   $   $   $ 127,374  
  Commodity derivative losses (realized)     (12,789 )               (12,789 )
  Commodity derivative losses (unrealized)     (14,977 )               (14,977 )
  Other     2,861     129     2,744     (2,354 )   3,380  
   
 
 
 
 
 
    Total revenues     76,026     26,572     2,744     (2,354 )   102,988  
   
 
 
 
 
 
EXPENSES:                                
  Oil and natural gas production     25,301     9,324     893         35,518  
  Transportation expense     3,411     60         (1,861 )   1,610  
  Depletion, depreciation and amortization     17,902     5,500     95         23,497  
  Accretion of abandonment liability     904     196     11         1,111  
  General and administrative, net of amounts capitalized     12,170     242     202     (493 )   12,121  
  Amortization of deferred loan costs     1,471                 1,471  
  Interest, net     19,653     (20 )   (1,004 )       18,629  
   
 
 
 
 
 
    Total expenses     80,812     15,302     197     (2,354 )   93,957  
   
 
 
 
 
 
Equity in subsidiary income     8,290             (8,290 )    
   
 
 
 
 
 
Income before income taxes     3,504     11,270     2,547     (8,290 )   9,031  
Income tax provision (benefit)     (1,927 )   4,508     1,019         3,600  
   
 
 
 
 
 
Net income   $ 5,431   $ 6,762   $ 1,528   $ (8,290 ) $ 5,431  
   
 
 
 
 
 

F-46



CONDENSED CONSOLIDATING BALANCE SHEETS

AT DECEMBER 31, 2004 (Successor)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-Guarantor
Subsidiaries

  Eliminations
  Consolidated
ASSETS                              
CURRENT ASSETS:                              
  Cash and cash equivalents   $ 54,665   $   $ 50   $   $ 54,715
  Accounts receivable     17,210         545         17,755
  Inventories     1,079                 1,079
  Prepaid expenses and other current assets     3,244         187         3,431
  Notes receivable—officers     1,420                 1,420
  Income tax receivable     3,906                 3,906
  Deferred income taxes     209                 209
  Commodity derivatives     5,300                 5,300
   
 
 
 
 
TOTAL CURRENT ASSETS     87,033         782         87,815
   
 
 
 
 
  PROPERTY, PLANT & EQUIPMENT, NET     158,562     24,846     15,155         198,563
  COMMODITY DERIVATIVES     4,855                 4,855
  INVESTMENTS IN AFFILIATES     56,495             (56,495 )  
  DEFERRED LOAN COSTS     6,596                 6,596
  OTHER     1,053                 1,053
   
 
 
 
 
TOTAL ASSETS   $ 314,594   $ 24,846   $ 15,937   $ (56,495 ) $ 298,882
   
 
 
 
 

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
CURRENT LIABILITIES:                              
  Accounts payable and accrued liabilities   $ 19,038   $   $ 347   $   $ 19,385
  Undistributed revenue payable     4,774                 4,774
  Current maturities of long-term debt             127         127
  Commodity derivatives     1,520                 1,520
  Repurchase of common stock     5,316                 5,316
   
 
 
 
 
TOTAL CURRENT LIABILITIES     30,648         474         31,122
   
 
 
 
 
LONG-TERM DEBT     153,727         9,815         163,542
DEFERRED INCOME TAXES     32,208                 32,208
ASSET RETIREMENT OBLIGATIONS     21,526     1,236     422         23,184
INTERCOMPANY PAYABLES (RECEIVABLES)     27,659     (14,128 )   (13,531 )      
   
 
 
 
 
TOTAL LIABILITIES     265,768     (12,892 )   (2,820 )       250,056
   
 
 
 
 
Minority interest in Marquez Energy     387                 387
TOTAL STOCKHOLDERS' EQUITY     48,439     37,738     18,757     (56,495 )   48,439
   
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY   $ 314,594   $ 24,846   $ 15,937   $ (56,495 ) $ 298,882
   
 
 
 
 

F-47



CONDENSED CONSOLIDATING BALANCE SHEETS

AT DECEMBER 31, 2005 (Successor)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-Guarantor
Subsidiaries

  Eliminations
  Consolidated
ASSETS                              
CURRENT ASSETS:                              
  Cash and cash equivalents   $ 9,041   $   $ 348   $   $ 9,389
  Accounts receivable     29,253     490     98         29,841
  Inventories     1,753                 1,753
  Commodity derivatives     3,391                 3,391
  Prepaid expenses and other current assets     3,894         457         4,351
  Income taxes receivable     4,107                 4,107
  Deferred income taxes     8,611                 8,611
   
 
 
 
 
TOTAL CURRENT ASSETS     60,050     490     903         61,443
   
 
 
 
 
  PROPERTY, PLANT & EQUIPMENT, NET     222,798     17,756     14,868     (21,646 )   233,776
  COMMODITY DERIVATIVES     69                 69
  INVESTMENTS IN AFFILIATES     69,651             (69,651 )  
  OTHER     7,270                 7,270
   
 
 
 
 
TOTAL ASSETS   $ 359,838   $ 18,246   $ 15,771   $ (91,297 ) $ 302,558
   
 
 
 
 

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
CURRENT LIABILITIES:                              
  Accounts payable and accrued liabilities   $ 31,784     10     60       $ 31,854
  Undistributed revenue payable     2,155                 2,155
  Current maturities of long-term debt             126         126
  Commodity derivatives     26,397                 26,397
   
 
 
 
 
TOTAL CURRENT LIABILITIES     60,336     10     186         60,532
   
 
 
 
 
LONG-TERM DEBT     169,180         9,763         178,943
DEFERRED INCOME TAXES     24,108                 24,108
ASSET RETIREMENT OBLIGATIONS     21,507     701     441         22,649
INTERCOMPANY PAYABLES (RECEIVABLES)     68,381     (49,325 )   (19,056 )      
OTHER LIABILITIES     11,992                 11,992
   
 
 
 
 
TOTAL LIABILITIES     355,504     (48,614 )   (8,666 )       298,224
   
 
 
 
 
TOTAL STOCKHOLDERS' EQUITY     4,334     66,860     24,437     (91,297 )   4,334
   
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY   $ 359,838   $ 18,246   $ 15,771   $ (91,297 ) $ 302,558
   
 
 
 
 

F-48



CONDENSED CONSOLIDATING BALANCE SHEETS

AT JUNE 30, 2006 (Successor) (Unaudited)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-
Guarantor
Subsidiaries

  Eliminations
  Consolidated
ASSETS:                              
CURRENT ASSETS:                              
  Cash and cash equivalents   $ 83   $ 13,258   $ 46   $   $ 13,387
  Accounts receivable     27,887     12,713     69         40,669
  Inventories     2,177                 2,177
  Prepaid expenses and other current assets     3,379     1,859             5,238
  Income taxes receivable     2,811                 2,811
  Deferred income taxes     9,673                 9,673
  Commodity derivatives     7,507                 7,507
   
 
 
 
 
TOTAL CURRENT ASSETS     53,517     27,830     115         81,462
   
 
 
 
 
  PROPERTY, PLANT & EQUIPMENT, NET     280,815     483,097     975     (21,664 )   743,223
  COMMODITY DERIVATIVES     6,642                 6,642
  INVESTMENTS IN AFFILIATES     540,039             (540,039 )  
  OTHER     20,987     985             21,972
   
 
 
 
 
TOTAL ASSETS   $ 902,000   $ 511,912   $ 1,090   $ (561,703 ) $ 853,299
   
 
 
 
 
LIABILITIES AND STOCKHOLDERS' EQUITY                              
CURRENT LIABILITIES:                              
  Accounts payable and accrued liabilities   $ 30,860   $ 12,487   $   $   $ 43,347
  Undistributed revenue payable     513     10,304             10,817
  Accrued interest     11,380     (1 )           11,379
  Commodity derivatives     33,344                 33,344
   
 
 
 
 
TOTAL CURRENT LIABILITIES:     76,097     22,790             98,887
   
 
 
 
 
LONG-TERM DEBT     658,777                 658,777
DEFERRED INCOME TAXES     24,635                 24,635
COMMODITY DERIVATIVES     29,394                 29,394
ASSET RETIREMENT OBLIGATIONS     25,488     8,478     452         34,418
INTERCOMPANY PAYABLES (RECEIVABLES)     80,421     (51,442 )   (28,979 )      
OTHER LONG-TERM LIABILITIES     1,901                 1,901
   
 
 
 
 
TOTAL LIABILITIES     896,713     (20,174 )   (28,527 )       848,012
   
 
 
 
 
TOTAL STOCKHOLDERS' EQUITY     5,287     532,086     29,617     (561,703 )   5,287
   
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY   $ 902,000   $ 511,912   $ 1,090   $ (561,703 ) $ 853,299
   
 
 
 
 

F-49



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2003 (Predecessor)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
OPERATING ACTIVITIES                                
  Net cash provided by operating activities   $ 21,770   $ 4,524   $ 5,263   $   $ 31,557  
CASH FLOWS FROM INVESTING ACTIVITIES:                                
  Expenditures for oil and natural gas properties     (9,180 )   (595 )   (978 )       (10,753 )
  Expenditures for other property and equipment     (32 )               (32 )
  Proceeds from sale of oil and natural gas properties     1                 1  
  Proceeds from sale of other property and equipment     16                 16  
  Notes receivable—officers and employees     237                 237  
   
 
 
 
 
 
    Net cash used in investing activities     (8,958 )   (595 )   (978 )       (10,531 )
   
 
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:                                
  Net proceeds from intercompany borrowings     8,177     (3,929 )   (4,248 )        
  Principal payments on long-term debt     (23,333 )               (23,333 )
   
 
 
 
 
 
    Net cash used in financing activities     (15,156 )   (3,929 )   (4,248 )       (23,333 )
   
 
 
 
 
 
Net (decrease) increase in cash and cash equivalents     (2,344 )       37         (2,307 )
Cash and cash equivalents, beginning of year     10,716         8         10,724  
   
 
 
 
 
 
Cash and cash equivalents, end of year   $ 8,372   $   $ 45   $   $ 8,417  
   
 
 
 
 
 

F-50



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2004 (Predecessor)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
OPERATING ACTIVITIES                                
  Net cash provided by operating activities   $ 32,092   $ 6,094   $ 5,123   $   $ 43,309  
CASH FLOWS FROM INVESTING ACTIVITIES:                                
  Expenditures for oil and natural gas properties     (15,449 )   (684 )   (213 )       (16,346 )
  Expenditures for other property and equipment     (245 )   (16 )           (261 )
  Purchase of new building             (14,653 )       (14,653 )
  Proceeds from sale of oil and natural gas properties     1,526                 1,526  
  Proceeds from sale of other property and equipment             228         228  
  Acquisition of Marquez Energy     (672 )               (672 )
  Notes receivable—officers and employees     2,188                 2,188  
   
 
 
 
 
 
    Net cash used in investing activities     (12,652 )   (700 )   (14,638 )       (27,990 )
   
 
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:                                
  Net proceeds from intercompany borrowings     5,815     (5,394 )   (421 )        
  Proceeds from long-term debt     262,397         10,000         272,397  
  Principal payments on long-term debt     (159,595 )       (59 )       (159,654 )
  Increase in deferred loan costs     (9,653 )               (9,653 )
  Purchase of preferred stock and unpaid dividends     (72,000 )               (72,000 )
  Contributions from Marquez Energy members     500                 500  
  Distribution payments to Marquez Energy members     (611 )               (611 )
   
 
 
 
 
 
    Net cash (used in) provided by financing activities     26,853     (5,394 )   9,520         30,979  
   
 
 
 
 
 
Net increase in cash and cash equivalents     46,293         5         46,298  
Cash and cash equivalents, beginning of period     8,372         45         8,417  
   
 
 
 
 
 
Cash and cash equivalents, end of period   $ 54,665   $   $ 50   $   $ 54,715  
   
 
 
 
 
 

F-51



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2005 (Successor)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
OPERATING ACTIVITIES                                
  Net cash provided by operating activities   $ 27,873   $ 6,174   $ 5,884   $   $ 39,931  
CASH FLOWS FROM INVESTING ACTIVITIES:                                
  Expenditures for oil and natural gas properties     (72,217 )   (16,068 )   (8 )       (88,293 )
  Expenditures for other property and equipment     (1,813 )               (1,813 )
  Proceeds from sale of oil and natural gas properties         44,619             44,619  
  Acquisition of Marquez Energy, LLC     (14,628 )               (14,628 )
  Notes receivable—officers and employees         1,420             1,420  
   
 
 
 
 
 
    Net cash (used in) provided by investing activities     (88,658 )   29,971     (8 )       (58,695 )
  Net proceeds from (repayments of) intercompany borrowings     37,869     (32,344 )   (5,525 )        
  Proceeds from long-term debt     59,000                 59,000  
  Principal payments on long-term debt     (39,000 )   (4,684 )   (53 )       (43,737 )
  Increase in deferred loan costs     (817 )               (817 )
  Payments of dividends     (35,000 )               (35,000 )
  Distribution payments to Marquez Energy member         (707 )           (707 )
  Repurchase common stock     (5,301 )               (5,301 )
   
 
 
 
 
 
    Net cash (used in) provided by financing activities     16,751     (37,735 )   (5,578 )       (26,562 )
   
 
 
 
 
 
Net (decrease) increase in cash and cash equivalents     (44,034 )   (1,590 )   298         (45,326 )
Cash and cash equivalents, beginning of period     53,075     1,590     50         54,715  
   
 
 
 
 
 
Cash and cash equivalents, end of period   $ 9,041   $   $ 348   $   $ 9,389  
   
 
 
 
 
 

F-52



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2005 (Successor) (Unaudited)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-
Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
OPERATING ACTIVITIES:                                
  Net cash provided by operating activities   $ 23,461   $ 1,555   $ 3,205   $   $ 28,221  
CASH FLOWS FROM INVESTING ACTIVITIES:                                
  Capital expenditures for oil and gas properties     (31,469 )   (581 )           (32,050 )
  Acquisition of Marquez Energy, LLC     (14,628 )               (14,628 )
  Proceeds from sale of oil and gas properties         44,619             44,619  
  Increase in cash restricted for investment in oil and gas properties         (44,619 )           (44,619 )
  Notes receivable—officers and employees     1,390                 1,390  
  Capital expenditures for property and equipment and other     (759 )               (759 )
   
 
 
 
 
 
    Net cash used in investing activities     (45,466 )   (581 )           (46,047 )
   
 
 
 
 
 
  Net proceeds from (repayments of) intercompany borrowings     3,978     (974 )   (3,004 )        
  Proceeds from long-term debt     23,000                 23,000  
  Principal payments on long-term debt     (12,684 )       7         (12,677 )
  Distribution payments to Marquez Energy member     (707 )               (707 )
  Payments of dividends     (35,000 )               (35,000 )
  Repurchase of common stock     (5,245 )               (5,245 )
  Increase in deferred loan costs     (599 )               (599 )
   
 
 
 
 
 
    Net cash used in financing activities     (27,257 )   (974 )   (2,997 )       (31,228 )
   
 
 
 
 
 
  Net increase (decrease) in cash and cash equivalents     (49,262 )       208         (49,054 )
  Cash and cash equivalents, beginning of period     54,665         50           54,715  
   
 
 
 
 
 
  Cash and cash equivalents, end of period   $ 5,403   $   $ 258   $   $ 5,661  
   
 
 
 
 
 

F-53



CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2006 (Successor) (Unaudited)

(in thousands)

 
  Venoco, Inc.
  Guarantor
Subsidiaries

  Non-
Guarantor
Subsidiaries

  Eliminations
  Consolidated
 
OPERATING ACTIVITIES:                                
  Net cash provided by (used in) operating activities   $ 55,237   $ 7,296   $ (2,163 ) $   $ 60,370  
CASH FLOWS FROM INVESTING ACTIVITIES:                                
  Capital expenditures for oil and gas properties     (69,434 )   (14,040 )           (83,474 )
  Proceeds from sale of oil and gas properties         3,031             3,031  
  Investment in Texcal, net of cash received     (456,810 )   9,291             (447,519 )
  Capital expenditures for property and equipment and other     (3,259 )   (41 )           (3,300 )
   
 
 
 
 
 
    Net cash used in investing activities     (529,503 )   (1,759 )           (531,262 )
  Net proceeds from (repayments of) intercompany borrowings     (9,615 )   7,721     1,894          
  Proceeds from long-term debt     504,529                 504,529  
  Principal payments on long-term debt     (15,000 )       (33 )       (15,033 )
  Payments of dividends     (426 )               (426 )
  Increase in deferred loan costs     (14,180 )               (14,180 )
   
 
 
 
 
 
    Net cash provided by financing activities     465,308     7,721     1,861         474,890  
   
 
 
 
 
 
  Net increase (decrease) in cash and cash equivalents     (8,958 )   13,258     (302 )       3,998  
  Cash and cash equivalents, beginning of period     9,041         348         9,389  
   
 
 
 
 
 
  Cash and cash equivalents, end of period   $ 83   $ 13,258   $ 46   $   $ 13,387  
   
 
 
 
 
 

F-54



INDEPENDENT AUDITORS' REPORT

To the Unitholders and Board of Directors
TexCal Energy (LP) LLC
Wilmington, Delaware

        We have audited the accompanying consolidated balance sheets of TexCal Energy (LP) LLC ("Successor") as of December 31, 2004 and 2005, and the related consolidated statements of operations, members' equity and cash flows for the period from the Successor's inception of operations (October 1, 2004) through December 31, 2004 and for the year ended December 31, 2005, and the statements of operations, capital deficit and cash flows of Tri-Union Development Corporation ("Predecessor" as described in Note 1 of the notes to consolidated financial statements) for the year ended December 31, 2003 and for the period from January 1, 2004 to September 30, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the Successor consolidated financial statements referred to above present fairly, in all material respects, the financial position of TexCal Energy (LP) LLC at December 31, 2004 and 2005, and the results of its operations and its cash flows for the period from the Successor's inception of operations (October 1, 2004) through December 31, 2004 and for the year ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor consolidated financial statements referred to above present fairly, in all material aspects, the results of operations and cash flows of the Predecessor for the year ended December 31, 2003 and for the period from January 1, 2004 to September 30, 2004, in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Notes 1 and 2 to the consolidated financial statements, effective October 1, 2004, the Successor acquired a majority of the operations of the Predecessor in a business combination accounted for as a purchase. As a result of the acquisition, the consolidated financial statements for the period after the acquisition are presented on a different cost basis than that for the periods before the acquisition and, therefore, are not comparable.

        As discussed in Note 6 to the consolidated financial statements, effective January 1, 2003, the Predecessor changed its method of accounting for asset retirement obligations.

/s/ BDO SEIDMAN, LLP

BDO Seidman, LLP

Houston, Texas
March 23, 2006

F-55



TEXCAL ENERGY (LP) LLC

CONSOLIDATED BALANCE SHEETS

(In thousands)

 
  Successor
December 31,

 
 
  2004
  2005
 
ASSETS              
CURRENT ASSETS:              
  Cash and cash equivalents   $ 6,595   $ 20,845  
  Restricted cash     1,087     1,110  
  Accounts receivable, net of allowance for doubtful accounts of $1,335 and $605 at December 31, 2004 and 2005, respectively     6,265     16,934  
  Prepaid expenses and other current assets     1,013     1,687  
  Commodity derivatives         101  
   
 
 
    Total current assets     14,960     40,677  
   
 
 
PROPERTY, PLANT AND EQUIPMENT, AT COST:              
  Oil and natural gas properties—full cost method     124,020     144,160  
  Other property and equipment     419     704  
   
 
 
      Total property, plant, and equipment     124,439     144,864  
  Accumulated depletion, depreciation and amortization     (1,726 )   (12,442 )
   
 
 
      Net property, plant, and equipment     122,713     132,422  
   
 
 
OTHER ASSETS:              
  Deferred loan costs, net     309     209  
  Other     1,661     809  
   
 
 
    Total other assets     1,970     1,018  
   
 
 
TOTAL ASSETS   $ 139,643   $ 174,117  
   
 
 

LIABILITIES AND MEMBERS' EQUITY

 

 

 

 

 

 

 
CURRENT LIABILITIES:              
  Accounts payable and accrued liabilities   $ 8,554   $ 10,672  
  Undistributed revenue payable     8,720     12,093  
  Accrued interest     62     25  
  Members' distributions         2,432  
  Commodity derivatives     4,033      
   
 
 
    Total current liabilities     21,369     25,222  
 
LONG-TERM DEBT

 

 

9,000

 

 


 
  ASSET RETIREMENT OBLIGATIONS     6,837     7,816  
   
 
 
    Total liabilities     37,206     33,038  
COMMITMENTS AND CONTINGENCIES              
MEMBERS' EQUITY:              
  Members' units     98,000     98,000  
  Accumulated earnings     4,437     43,079  
   
 
 
    Total members' equity     102,437     141,079  
   
 
 
TOTAL LIABILITIES AND MEMBERS' EQUITY   $ 139,643   $ 174,117  
   
 
 

See accompanying notes to consolidated financial statements.

F-56



TEXCAL ENERGY (LP) LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

 
  Predecessor
  Successor
 
 
  Year Ended
December 31,
2003

  Nine
Months Ended
September 30,
2004

  Inception to
December 31,
2004

  Year Ended
December 31,
2005

 
REVENUES:                          
  Oil and natural gas sales   $ 41,673   $ 31,688   $ 11,353   $ 82,336  
  Commodity derivative losses (realized)     (8,865 )   (11,716 )   (6,201 )   (3,210 )
  Commodity derivative losses (unrealized)     (3,910 )   (88 )   7,207     2,975  
  Other     280     309     44     1,069  
   
 
 
 
 
    Total revenues     29,178     20,193     12,403     83,170  
   
 
 
 
 
EXPENSES:                          
  Oil and natural gas production     16,485     11,706     4,808     22,201  
  Transportation expense     839     520     20     172  
  Depletion, depreciation and amortization     6,460     4,173     1,727     10,745  
  Accretion of abandonment liability     3,047     1,942     132     527  
  General and administrative, net of amounts capitalized     6,596     3,879     1,048     3,975  
  Amortization of deferred loan costs     3,572         21     117  
  Interest, net     16,291     11     210     828  
   
 
 
 
 
    Total expenses     53,290     22,231     7,966     38,565  
   
 
 
 
 
  Income (loss) before reorganization costs, cumulative effect of change in accounting principle and income taxes     (24,112 )   (2,038 )   4,437     44,605  
Reorganization costs     963     6,597          
   
 
 
 
 
  Income (loss) before cumulative effect of change in accounting principle and income taxes     (25,075 )   (8,635 )   4,437     44,605  
Benefit for income taxes         18,745          
   
 
 
 
 
  Income (loss) before cumulative effect of change in accounting principle     (25,075 )   10,110     4,437     44,605  
Cumulative effect of change in accounting principle     11,460              
   
 
 
 
 
Net (loss) income   $ (36,535 ) $ 10,110   $ 4,437   $ 44,605  
   
 
 
 
 

See accompanying notes to consolidated financial statements.

F-57



TEXCAL ENERGY (LP) LLC

CONSOLIDATED STATEMENTS OF CAPITAL DEFICIT AND MEMBERS' EQUITY

(In thousands, except per share amounts)

 
  Class A
Common Stock

  Class B
Common Stock

   
   
   
 
 
  Additional
Paid in
Capital

  Accumulated
Deficit

   
 
 
  Shares
  Amount
  Shares
  Amount
  Total
 
Predecessor:                                        
Balance, December 31, 2002   445,000   $ 4   65,000   $ 1   $ 26,066   $ (53,176 ) $ (27,105 )
  Net loss                     (36,535 )   (36,535 )
   
 
 
 
 
 
 
 
Balance, December 31, 2003   445,000     4   65,000     1     26,066     (89,711 )   (63,640 )
  Net income                     10,110     10,110  
   
 
 
 
 
 
 
 
Balance, September 30, 2004   445,000   $ 4   65,000   $ 1   $ 26,066   $ (79,601 ) $ (53,530 )
   
 
 
 
 
 
 
 
 
  Members' Units
   
   
 
 
  Accumulated
Earnings

   
 
 
  Units
  Amount
  Total
 
Successor:                        
Issuance of members' units at inception (October 1, 2004)   118,125   $ 98,000   $   $ 98,000  
  Net income           4,437     4,437  
   
 
 
 
 
Balance at December 31, 2004   118,125     98,000     4,437     102,437  
  Net income           44,605     44,605  
  Members' distributions           (5,964 )   (5,964 )
   
 
 
 
 
Balance at December 31, 2005   118,125   $ 98,000   $ 43,078   $ 141,078  
   
 
 
 
 

See accompanying notes to consolidated financial statements.

F-58



TEXCAL ENERGY (LP) LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 
  Predecessor
  Successor
 
 
  Year Ended
December 31,
2003

  Nine
Months Ended
September 30,
2004

  Inception to
December 31,
2004

  Year Ended
December 31,
2005

 
CASH FLOW FROM OPERATING ACTIVITIES:                          
  Net (loss) income   $ (36,535 ) $ 10,110   $ 4,436   $ 44,605  
  Adjustments to reconcile net (loss) income to net cash provided by operating activities:                          
    Benefit for income taxes         (18,745 )        
    Cumulative effect of change in accounting principle     11,460              
    Depletion, depreciation and amortization     6,461     4,173     1,727     10,745  
    Accretion of abandonment liability     3,047     1,942     132     527  
    Amortization of bond discounts     4,152              
    Amortization of deferred loan costs     3,571         21     117  
    Provision for doubtful accounts     194     459         448  
    Reorganization costs, net     963     6,597          
    Commodity derivative losses (gains)     12,776     11,804     (1,006 )   235  
    Other     307     (24 )   18     (32 )
  Changes in assets and liabilities, net of acquired assets and liabilities:                          
    Accounts receivable     (638 )   474     (542 )   (10,638 )
    Prepaid expenses and other current assets     1,274     1,068     (57 )   (697 )
    Other assets     1,299     150     (119 )   378  
    Accounts payable and other liabilities     (15,928 )   2,420     (2,387 )   5,131  
    Pre-petition liabilities subject to compromise     35,849     122          
    Asset retirement obligation     (8,478 )   (1,270 )       (375 )
   
 
 
 
 
      Net cash provided by operating activities before reorganization items     19,774     19,280     2,223     50,444  
   
 
 
 
 
OPERATING CASH FLOWS FROM REORGANIZATION                          
  Items:                          
    Bankruptcy related professional fees paid     (1,213 )   (5,413 )        
   
 
 
 
 
      Net cash provided by operating activities     18,561     13,867     2,223     50,444  
   
 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:                          
  Cash related to acquisition of assets and liabilities             3,246      
  Expenditures for oil and natural gas properties     (4,714 )   (926 )   (1,210 )   (22,131 )
  Expenditures for other property and equipment     (130 )   (40 )   (69 )   (359 )
  Proceeds from sale of oil and natural gas properties     301     20         3,250  
  Proceeds from sale of other property and equipment     30     4         70  
  Cash settlements on commodity derivatives     (8,085 )   (11,606 )   (6,265 )   (4,369 )
   
 
 
 
 
      Net cash used in investing activities     (12,598 )   (12,548 )   (4,298 )   (23,539 )
   
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:                          
  Proceeds from long-term debt             9,000     2,000  
  Principal payments on long-term debt                 (11,000 )
  Deferred loan costs             (330 )   (16 )
  Payment of other liabilities     (1,798 )            
  Members' distributions                 (3,639 )
   
 
 
 
 
      Net cash provided by (used in) financing activities     (1,798 )       8,670     (12,655 )
   
 
 
 
 
Net increase in cash and cash equivalents     4,165     1,319     6,595     14,250  
Cash and cash equivalents—beginning of period     1,542     5,706         6,595  
   
 
 
 
 
Cash and cash equivalents—end of period   $ 5,707   $ 7,025   $ 6,595   $ 20,845  
   
 
 
 
 
Supplemental disclosure of cash flow information:                          
  Cash paid during the year for:                          
    Interest   $ 20   $ 10   $ 220   $ 749  
    Asset retirement obligation costs and liabilities   $ 14,082   $ (51 ) $ 7,242   $ 1,258  
  Reorganization costs accrued in accounts payable and accrued liabilities   $ 293   $ 1,395   $   $  
Supplemental disclosure of non-cash activities:                          
  Accrued members' distribution   $   $   $   $ 2,324  

See accompanying notes to consolidated financial statements.

F-59



TEXCAL ENERGY (LP) LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Description of the Company and Basis of Presentation

Description of the Company

        TexCal Energy (LP) LLC (along with its subsidiaries, collectively the "Company" or the "Successor") is an independent oil and natural gas company. The Company's properties are comprised of a portion of the former business of Tri-Union Development Corporation ("TDC" or the "Predecessor"). The Company is engaged in the acquisition, operation and development of oil and natural gas properties located onshore in the Texas Gulf Coast region and in the Sacramento Basin of northern California.

        TexCal Energy (LP) LLC (the "Limited Partner") is a limited liability company formed in the State of Delaware in August 2003. The Limited Partner did not conduct any business activities until October 1, 2004. The Limited Partner has four subsidiaries, each of which is directly or indirectly wholly-owned. TexCal Energy (GP) LLC (the "General Partner") is a limited liability company formed in the State of Delaware and is directly wholly owned by the Limited Partner. The General Partner owns a .001% interest in three (3) subsidiaries, TexCal Energy North Cal L.P., TexCal Energy South Cal L.P. and TexCal Energy South Texas L.P., each of which is a partnership formed in the State of Texas in September 2004, hereinafter collectively referred to as "Subsidiaries," with the remaining 99.999% interest being owned by the Limited Partner. The Limited Partner is a privately held entity wholly owned by the former Noteholders of TDC (see Note 2).

Basis of Presentation

        The results of operations and cash flows and related disclosures for periods prior to October 1, 2004, the effective date of the transaction in which the Company acquired its properties from the Predecessor (the "Effective Date"), are presented as the results of the Predecessor. The financial position, results of operations and cash flows and related disclosures subsequent to the Effective Date as of and for the three months ended December 31, 2004 and for the year ended December 31, 2005 are those of the Successor.

        The consolidated financial statements of the Successor as of and from Inception (October 1, 2004) to December 31, 2004 and for the year ended December 31, 2005 reflect the acquisition of TDC under the purchase method of accounting in accordance with Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 141, Business Combinations.

        The results of the Successor are not comparable to the results of the Predecessor as they are presented on a different cost basis from that for the periods before the Effective Date. Furthermore, all amounts contained within the Predecessor's consolidated financial statements for the year ended December 31, 2003 and the nine months ended September 30, 2004 include oil and natural gas properties located offshore in the shallow waters of the Gulf of Mexico which were not acquired by the Successor and costs related to the bankruptcy of the Predecessor.

        In accordance with GAAP, the Predecessor has applied American Institute of Certified Public Accountants' ("AICPA") Statement of Position 90-7, "Financial Reporting by Entities in Reorganization under the Bankruptcy Code" ("SOP 90-7"), in preparing the Consolidated Financial Statements for the year ended December 31, 2003 and for the nine months ended September 30, 2004. SOP 90-7 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses (including professional fees), realized gains and losses

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and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in reorganization costs, net on the accompanying Consolidated Statements of Operations. As noted above, the Successor, which acquired certain assets and liabilities from the Predecessor, was not the debtor in bankruptcy, and, as such, did not apply SOP 90-7.

Note 2—Acquisition of Certain Assets and Liabilities

        The Successor was formed to acquire certain assets, liabilities and operations of TDC and its subsidiary, Tri-Union Operating Company ("TOC"). During 2003, TDC was in default on approximately $118 million of its 12.5% senior secured notes due 2006 (the "TDC Notes"). Unable to pay or restructure these obligations, on October 20, 2003, TDC and TOC filed for protection under Chapter 11 ("Current Bankruptcy Case") of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division. TDC filed a Plan of Reorganization immediately upon commencement of the case. TDC's Plan provided for a credit bid process pursuant to the terms of a Purchase and Sale Agreement ("PSA"). The PSA provided a structure under which the Company, in exchange for the TDC Notes contributed to it by the Noteholders, or any other qualified buyer bidding with cash, could purchase certain of TDC's and TOC's Texas onshore and California oil and natural gas assets and certain other assets in the form of cash, accounts receivable, prepaid expenses, furniture, fixtures and equipment, restricted cash balances and other assets net of certain liabilities in the form of accounts payable, accrued liabilities and a liability associated with hedge contracts (hereinafter referred to as the "Acquisition Assets and Liabilities"). The terms of the PSA required a minimum starting bid of $98 million. In August 2004, a structured one-day auction was held at which time the Company utilized $98 million of its TDC Notes to acquire the Acquisition Assets and Liabilities (the "Acquisition").

        Effective October 1, 2004 (date of "Inception"), TDC and TOC transferred to the Company their rights, title and interest in the Acquisition Assets and Liabilities pursuant to the terms of the PSA. The remaining assets, liabilities and operations of TDC and TOC relate to Texas offshore oil and natural gas operations that were not purchased by the Company. The holders of the TDC Notes received a number of issued and outstanding common units of the Limited Partner based on the proportionate amount of TDC Notes owned by them. Each holder of a $1,000 TDC Note was entitled to a single Class A common unit of the Limited Partner pursuant to the rights, preferences and limitations as set forth in the Amended and Restated Limited Liability Company Agreement of the Limited Partner ("LLC Agreement") dated as of September 30, 2004. As of December 31, 2004 and 2005, the Limited Partner had 118,125 units authorized and issued. Each holder of Class A common units of the Limited Partner is a member in the Limited Partner.

        The Company recorded the Acquisition Assets and Liabilities at their respective fair-market values as prescribed by SFAS 141, Accounting for Business Combinations. SFAS 141 prescribes the method whereby assets acquired in exchange transactions that trigger the initial recognition of the assets acquired and any liabilities assumed or incurred, and equity shares issued are recorded. Initial members' equity was recorded at the $98 million of notes used to acquire the Acquisition Assets and

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Liabilities. The table below summarizes the assets and liabilities conveyed to or assumed by the Company and its Subsidiaries as of October 1, 2004, and their fair-market values (in thousands):

Current assets   $ 10,279
Oil and natural gas properties     115,569
Other non-current assets     1,909
   
  Total acquisition assets   $ 127,757
   
Accounts payable and accrued liabilities   $ 18,453
Derivative contracts     11,304
Members' equity     98,000
   
Total acquisition liabilities and members' equity   $ 127,757
   

Note 3—Summary of Significant Accounting Policies

Consolidation Principles

        The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("U.S. GAAP") for all periods presented and include the accounts of the Company and its subsidiaries.

Use of Estimates

        The accompanying consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant assumptions are required in the quantification and valuation of proved oil and natural gas reserves, which as described herein may affect the amount at which oil and natural gas properties are recorded and related depreciation, depletion and amortization are calculated. Actual results could differ materially from these estimates.

Oil and Natural Gas Properties

        The Company follows the full cost method of accounting for oil and natural gas property acquisition, exploration and development activities. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and development of oil and natural gas reserves for each cost center are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals and the costs of drilling, completing and equipping oil and natural gas wells. Sales of oil and natural gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves. The Company operates within one cost center comprised of the United States of America.

        Capitalized costs of proved oil and natural gas properties are depleted on a unit of production method using estimated proved oil and natural gas reserves. The amortizable base used to calculate

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unit of production depletion includes estimated future development costs and dismantlement, restoration, and abandonment costs, net of estimated salvage values.

        Internal costs, including salaries, benefits and other salary related costs, which can be directly identified with acquisition, exploration or development activities are capitalized, while any costs related to production, general corporate overhead, or similar activities are charged to expense. Geological and geophysical costs not directly associated with a specific unevaluated property are included in the amortization base as incurred. Capitalized internal costs directly identified with the Predecessor's acquisition, exploration and development activities amounted to approximately $1,262,000 and $604,000 during the year ended December 31, 2003 and for the nine months ended September 30, 2004, respectively. Capitalized internal costs directly identified with the Successor's acquisition, exploration and development activities, and included in capitalized oil and natural gas properties amounted to approximately $201,000 and $769,000 for the period from Inception through December 31, 2004 and for the year ended December 31, 2005, respectively.

        The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. In determining whether impairment of unevaluated properties has occurred, management evaluates, among other factors, current oil and natural gas industry conditions, capital availability, primary lease terms of the properties, holding periods of the properties, and available geological and geophysical data. Any impairment assessed is added to the costs being amortized. Costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that a well is dry. At December 31, 2004 and 2005, all of the Company's oil and natural gas properties were classified as evaluated and are included in the amortization base. The Company's proved oil and natural gas reserves were estimated by an independent petroleum engineering firm.

        The capitalized oil and natural gas property costs, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date to estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties excluded from the costs being amortized. No ceiling write down was recorded for any periods presented.

        General and administrative expenses are reported net of amounts allocated to working interest owners of the oil and natural gas properties operated by the Company, net of amounts charged for administrative and overhead costs and net of amounts capitalized pursuant to the full cost method of accounting.

Furniture, Fixtures and Equipment

        Furniture, fixtures and equipment are carried at cost. Depreciation is provided on the straight-line basis using estimated useful lives of three to ten years. At the time of a retirement or sale, the related cost and accumulated depreciation are removed from the accounts, and any resulting gain or loss is recorded to other income. Maintenance and repairs are charged to expense as incurred. Renewals, betterments and expenditures that increase the value of the property or extend its useful life are capitalized.

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Settlement Receivable

        During the second quarter of 2002, TDC participated in the successful drilling and completion of a well in Grimes County, Texas. The well was brought into production during the second quarter of 2002. The title to this well was in dispute with a former shareholder of TDC. TDC favorably resolved the title dispute during its Current Bankruptcy Case and entered into a settlement agreement, the terms of which require the disputing party to repay $1.1 million expended by TDC to drill and complete the well net of funds being held in an escrow account in the amount of $430,000 and $156,000 of suspended and unpaid royalties. TDC subsequently transferred its rights and interest in the settlement to the Company. The net receivable transferred to the Company was $826,000, which was subsequently reduced to $755,000 at December 31, 2004 and had a balance of $343,000 at December 31, 2005. The receivable is being repaid by the production proceeds, offset by lease operating expenses, from the well. Once the settlement receivable is paid in full, the Company will release title to the disputed interest.

Cash Equivalents

        The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Allowance for Doubtful Accounts

        Accounts receivable are customer obligations due under normal trade terms. The Company sells its oil and natural gas production to companies involved in the transportation and refining of oil and natural gas. The Company performs continuing credit evaluations of its customers' financial condition and although it generally does not require collateral, letters of credit may be required from customers in certain circumstances.

        Senior management reviews accounts receivable on a monthly basis to determine if any receivables will potentially be uncollectible. The Company includes any accounts receivable balances that are determined to be uncollectible in the overall allowance for doubtful accounts. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. Based on the information available, the Company believes the allowance for doubtful accounts as of December 31, 2005 is adequate. However, actual write-offs might exceed the recorded allowance.

Financial Instruments and Concentration of Credit Risk

        Financial instruments that subject the Company to credit risk consist of accounts receivable. The receivables are primarily from companies in the oil and natural gas industry or from individual oil and

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natural gas investors. The Company had revenues from certain customers representing 10% or greater of total revenues were as follows:

 
  Predecessor
  Successor
 
 
  Year Ended
December 31,
2003

  Nine
Months Ended
September 30,
2004

  Inception to
December 31,
2004

  Year Ended
December 31,
2005

 
Customer A   44 % 52 % 60 % 23 %
Customer B   8 % 10 % 13 % 6 %
Customer C   15 % 3 % 11 %  
Customer D         21 %
Customer E   9 % 14 % 4 % 20 %
Customer F         12 %

        Based on the general demand for oil and natural gas, the Company does not believe that a loss of any or all of these customers would have a material adverse effect on its financial condition or results of operations.

        In the case of receivables from joint interest owners, the Company may have the ability to offset amounts due against the participant's share of production from the related property.

        Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash deposits. Accounts at each institution are insured by the Federal Deposit Insurance Corporation (FDIC) up to $100,000. At December 31, 2004 and 2005, the Company had approximately $8.2 million and $22.1 million in excess of FDIC insured limits.

Fair Value of Financial Instruments

        The carrying values of cash and cash equivalents, accounts receivable, other assets and asset retirement obligations, as well as payables, approximate their fair values at December 31, 2004 and 2005 either due to the short term nature of the instrument or because the rates used to measure the instrument are reflective of current market rates. The fair value of the Company's credit facility is based on the current rates offered for debt with the same remaining maturities. The fair value and carrying value of the debt is $9.0 million and $0 at December 31, 2004 and December 31, 2005, respectively.

Income Taxes

    Successor

        The Limited Partner is a limited liability company. Consequently, its taxable income or loss is allocated to members in accordance with their respective percentage ownership. Therefore, no provision or liability for income taxes has been included in the accompanying consolidated financial statements.

        The Subsidiaries are limited partnerships. Consequently, they are not taxpaying entities for federal or state income tax purposes; accordingly, a provision for income taxes has not been recorded in the accompanying consolidated financial statements for the Subsidiaries. Partnership income or losses are reflected in the partners' individual or corporate income tax returns in accordance with their ownership percentages.

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    Predecessor

        The Predecessor accounts for income taxes using the "liability method." Accordingly, deferred tax liabilities or assets are determined based on temporary differences between the financial statement and income tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates is recognized in income in the period such change occurs. A valuation allowance is provided for deferred tax assets to the extent realization is judged to be unlikely.

Revenue Recognition

        The Company uses the sales method of accounting for natural gas and crude oil revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. The volumes sold may differ from the volumes to which the Company is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under produced owner to recoup its entitled share through production. There are no significant balancing arrangements or obligations related to the Company's operations.

Derivative Transactions

        The Company accounts for derivatives in accordance with Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB No. 133", and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" is in effect for the Company. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative. Derivatives that are not hedges are adjusted to fair value through income. If the derivative is a hedge, depending on the nature of the hedge, changes in the fair value of the derivatives are either offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings.

        Currently, the Company has not designated any of its commodity price derivative contracts as hedges under FAS No. 133; therefore, the Company has recorded these contracts at their estimated fair values, and included the changes in their fair values in the accompanying consolidated statements of operations.

        If at any time, the commodity derivative contracts result in a value due from the counterparty, the Company could be exposed to credit risk in the event of nonperformance by the counterparty in the commodity price derivative contracts; however, the Company does not anticipate nonperformance by any counterparty.

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Predecessor Reorganization Costs

        As a result of the Predecessor's Chapter 11 filings, the consolidated financial statements for the year ended December 31, 2003 and for the nine months ended September 30, 2004 have been prepared in accordance with SOP 90-7.

        Additionally, expenses incurred by the Predecessor as a result of its Chapter 11 reorganization have been presented separately in the consolidated statement of operations. This presentation is in accordance with SOP 90-7. The total amounts recorded for the year ended December 31, 2003 and for the nine months ended September 30, 2004 of $963,000 and $6,597,000, respectively, were comprised of the following amounts:

        Professional fees—The Predecessor was required to hire certain legal professionals to assist with its bankruptcy proceedings. These fees were $2,007,000 for the year ended December 31, 2003 and $6,647,000 for the nine months ended September 30, 2004.

        Claims Disposal—During the Predecessor's bankruptcy case, certain creditor claims were resolved. During the year ended December 31, 2003, $1,044,000 was recorded as a benefit to reorganization costs as a result of creditor claims disposal.

        Interest Income—During the nine months ended September 30, 2004, $50,000 of interest income was recorded as an offset to reorganization costs.

Note 4—Credit Facility

        On October 21, 2004, the Limited Partner, the General Partner and the Subsidiaries entered into a $50.0 million Revolving Line of Credit and Letter of Credit Facility Agreement ("Credit Facility"). The Credit Facility is secured by the oil and natural gas assets of the Company. The Credit Facility is subject to semi-annual borrowing base determinations. Initially the borrowing base was set at $25.0 million. The Credit Facility provides the Company with working capital to finance the acquisition and the development of its oil and natural gas assets. At the Company's option, interest accrues at prime rate less 25 basis points or LIBOR plus 275 basis points. Interest accrues at .375% on the unused portion of the Credit Facility. Interest is due semi-annually beginning December 31, 2004. The entire outstanding principal balance of the Credit Facility is due and payable three years from the effective date of the agreement, or on October 21, 2007. As of December 31, 2005 there was no outstanding principal balance.

        On October 21, 2004, a $14.4 million letter of credit was issued as collateral representing 130% of the marked-to-market liability of TDC's outstanding derivative contracts. At December 31, 2004, the outstanding letter of credit issued as collateral for the remaining hedge contracts had been reduced to $5.2 million. The Company pays a commitment fee of 2.75% on issued letters of credit. At December 31, 2005, the Company has one $250,000 letter of credit issued and outstanding. This letter of credit has been posted as collateral to the State of Texas for the Company's plugging and abandonment obligations.

        Among other requirements, the Credit Facility contains certain financial covenants requiring the Company to maintain a ratio of no less than 1.10 to 1.00 of current assets to current liabilities, as defined. Additionally, the Company is required to maintain tangible net worth, as defined, of no less than 80% of tangible net worth at closing, or $78,400,000, plus 50% of cumulative net income less the

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effects of the marked-to-market hedge contracts and TDC's restructuring costs assumed by the Company. Effective March 31, 2005, the Company's funded debt to EBITDA ratio, as defined, shall not exceed 3.5 to 1.00 and that ratio shall not exceed 3.00 to 1.00 thereafter. Funded debt is defined as the principal amount of all obligations of the borrowers under the facility, and the loans then outstanding with respect to the Credit Facility together with any outstanding letters of credit. Beginning with the quarter ended June 30, 2005, the Company's general and administrative costs may not exceed 20% of net operating income, as defined, for the relevant period on a consolidated basis. At December 31, 2004 and 2005, the Company was in compliance with all of the covenants in the Credit Facility.

Note 5—Derivative Financial Instruments

        The Company may use derivative instruments to manage its exposure to commodity prices. The Company's objectives for holding derivatives are to minimize risks using the most effective methods to eliminate or reduce the impact of this exposure. Currently, the Company has not designated any of its commodity price derivative contracts as hedges under FAS No. 133; therefore, the Company has recorded these contracts at their estimated fair values and included the changes in their fair values in the accompanying consolidated statements of operations.

    Successor

        At Inception, the Company assumed TDC's remaining commodity price derivative contracts, which had a marked-to-market liability of $11,304,000 on the date of Acquisition. At December 31, 2004, two months of TDC's commodity price derivative contracts remained outstanding and had a marked-to-market liability value of $4,033,000. The unrealized gain associated with these contracts in the amount of $1,006,000 is included in the unrealized gain on derivatives contracts in the accompanying December 31, 2004 consolidated statement of operations. As the assumed contracts matured during 2004 and 2005, the Company paid $6,266,000 and $4,485,000, respectively, to TDC's derivative counter-party. At December 31, 2005, all of the assumed TDC commodity price derivative contracts had been paid in full.

        In 2005 the Company placed additional commodity price derivative contracts with its hedge counter-party. At December 31, 2005, the Company had a receivable of $101,000 related to the settlement of its December 2005 commodity price derivative contract. In addition to the amounts paid for the assumed TDC contracts, the Company received $116,000 from its hedge counter-party in settlement of 2005 commodity price derivative contracts. At December 31, 2005, the Company had no commodity price derivative contracts in place against future production.

    Predecessor

        For the year ended December 31, 2003 and the nine months ended September 30, 2004, the Predecessor incurred losses on derivative contracts of $11,994,000 and $11,694,000, respectively. The estimated liability of $11,304,000 at September 30, 2004 associated with the oil and natural gas derivative contracts was assumed by the Company effective October 1, 2004 (see Note 2).

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Note 6—Asset Retirement Obligation

        The Company follows SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires that the fair value of a liability for an asset's retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying value of the long-lived asset. Subsequently, the asset retirement cost is amortized to expense over the useful life of the asset. The asset retirement obligation recorded relates to the expected plugging and abandonment costs of oil and natural gas wells and the removal of pipeline, compressor and related production facilities. As a result of the acquisition of oil and natural gas properties from TDC on October 1, 2004, the Company recorded a current asset retirement obligation of $531,000, a long-term retirement obligation of $6,711,000 and an increase to oil and natural gas properties of $7,242,000 based on the present value of the obligation. The present value of the asset retirement obligation will be accreted to full value over the remaining useful life of the Company's oil and natural gas properties and production facilities. As of December 31, 2004 and 2005, the Company had $906,000 and $467,000, respectively, classified in other assets for restricted cash and bonds pledged for the future plugging and abandonment of its oil and natural gas wells and related production facilities.

    Successor

        The changes to the Company's asset retirement obligation from Inception to December 31, 2004 and for the year ended December 31, 2005 are summarized as follows (in thousands):

Asset retirement obligation liability recognized at Inception (October 1, 2004)(1)   $ 7,242  
  Accretion expense     132  
   
 
Asset retirement obligation at December 31, 2004     7,374  
  Additions for new wells drilled     187  
  Accretion expense     526  
  Cash settlements for wells plugged and abandoned     (375 )
  Deletions for wells sold     (960 )
  Revisions to estimates     2,032  
   
 
Asset retirement obligation at December 31, 2005   $ 8,784  
   
 

(1)
The asset retirement obligation represents only obligations in respect of those properties acquired in the Acquisition, and is estimated based on variables relating specifically to the Successor, which differ from those variables used by the Predecessor in determining its asset retirement obligation.

        The current portion of asset retirement obligations of $537,000 and $968,000 at December 31, 2004 and 2005, respectively, is classified with accounts payable and accrued liabilities.

    Predecessor

        The adoption of SFAS 143 on January 1, 2003 resulted in the Predecessor recording a net-of-tax cumulative effect of change in accounting principle loss of $11,460,000, a current asset retirement obligation of $11,512,000, a long-term asset retirement obligation of $12,589,000 and an increase to oil and natural gas properties of $12,641,000.

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        The changes to the Predecessor's asset retirement obligation for the year ended December 31, 2003 and for the nine months ended September 30, 2004 are summarized as follows (in thousands):

Balance at December 31, 2002   $  
  Liability recognized upon adoption of SFAS 143     24,101  
  Additions for new wells drilled     22  
  Accretion expense     3,047  
  Cash settlements for wells plugged and abandoned     (8,478 )
  Revisions to estimates     1,418  
   
 
Balance at December 31, 2003     20,110  
  Accretion expense     1,942  
  Cash settlements for wells plugged and abandoned     (1,270 )
  Revisions to estimates     (51 )
   
 
Balance at September 30, 2004   $ 20,731  
   
 

Note 7—Predecessor Income Taxes

        Deferred income taxes result from differences between the basis of assets and liabilities as measured for income tax and financial reporting purposes.

        The following reconciles statutory federal income tax with the provision for income tax for the year ended December 31, 2003 and the nine months ended September 30, 2004 (in thousands):

 
  2003
  Nine Months
ended
September 30,
2004

 
Income tax benefit at statutory rate   $ (12,422 ) $ (2,936 )
Alternative minimum tax          
Non-deductible expenses     3     1  
Increase (decrease) in valuation allowance and other     12,419     (15,810 )
   
 
 
Benefit for income taxes   $   $ (18,745 )
   
 
 

        The benefit for income taxes for the nine months ended September 30, 2004 only relates to the expected utilization of approximately $54 million in net operating loss carryforwards from the transfer of certain oil and natural gas properties and liabilities by the Predecessor to the Successor on October 1, 2004 as more fully described in Note 2. The above benefit does not reflect any additional utilization of net operating loss carryforwards for the settlement of pre-petition liabilities in the bankruptcy proceedings.

Note 8—Commitments and Contingencies

Lease commitments

        The Successor has assumed certain of TDC's non-cancelable operating leases covering certain compression equipment and facilities and office space. Additionally, during 2005, the Company entered

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into a lease agreement for its current corporate office space. The following is a schedule of future minimum lease payments as of December 31, 2005 (in thousands):

Years Ending December 31,

   
2006   $ 920
2007     253
2008     274
2009     332
2010     186
   
    $ 1,965
   

        Rent expense incurred by the Successor under operating leases amounted to $657,000 from Inception (October 31, 2004) to December 31, 2004 and $2,196,000 during the year ended December 31, 2005. Rent expense incurred by the Predecessor under operating leases amounted to $2,684,000 for the year ended December 31, 2003 and $1,697,000 for the nine months ended September 30, 2004.

    Litigation

        At December 31, 2005, the Company is a defendant in a lawsuit, assumed from TDC, for breach of contract. Another lawsuit, assumed from TDC, relating to joint interest disputes was settled during 2005.

        Arch W. Helton et al. v. Tri-Union Development Corporation, in the United States Bankruptcy Court for the Southern District of Texas, Houston Division; related to Helton v. Tri-Union, in the 80th Judicial District Court of Harris County, Texas. On May 28, 1997, Arch W. Helton and Helton Properties, Inc. and later joined by Linda Barnhill (collectively "Helton parties") filed a lawsuit against TDC alleging that TDC owed additional royalties on oil and natural gas produced beginning in February 1987 through the initiation of the lawsuit with respect to 18 acres of property in Alvin, Texas. As to the Helton parties' largest claim, TDC received a favorable decision from the Texas Railroad Commission, which has been upheld on appeal. After a trial conducted in August and September 2003, the bankruptcy court issued a ruling that resulted in the full avoidance of all of the plaintiffs' claims. The Helton parties have appealed this decision with the Fifth Circuit Court of Appeals ("Fifth Circuit"). A briefing schedule has not been set by the Fifth Circuit. Approximately $1.1 million has been segregated pursuant to bankruptcy court order in accordance with the initial plan of reorganization pending resolution of this claim. The Company acquired TDC's interest in and claim to the $1.1 million of escrowed funds and the right to defend against any further claims brought by the Helton parties. The Company intends to vigorously defend against the appeal by the Helton parties.

        Samson Lone Star Limited Partnership ("Samson"), et al v. Tri-Union Development Corporation, in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. On August 31, 2004, Samson Lone Star Limited Partnership filed a lawsuit and a subsequent motion for a lifting and relief of the automatic stay, alleging that TDC's working interest in the Westbury Farms Gas Unit leases terminated because of TDC's alleged failure to consent to "save the lease" workover operations performed by Samson. TDC filed a response in opposition to the motion and engaged in discovery. The Company acquired TDC's interest in the leases and the right to defend against this

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matter. During August, 2005 the Company and Samson settled the lawsuit. Under the terms of the settlement agreement, all rights and interests of Tri-Union in the well, farmout leases, farmout agreement and assignments are assumed, assigned and transferred to the Company. Samson agreed to pay the Company $575,000, representing a portion of the net proceeds of production owed prior to July 1, 2005 based upon the Company's 25% working interest in the well. The Company's interest shall be a fully participating interest in the well and farmout leases. The Company shall be entitled to all net proceeds of or other funds from or attributable to its working interest in the well and farmout leases on and after July 1, 2005. Samson agreed to withdraw all claims in the bankruptcy cases and to consider all such claims resolved.

Potential litigation

        On February 24, 2006, James Cowan, a 38 year old man, was fatally injured while working as a gauger/pumper at a Company-operated well, the R. Casey No. 1 well in Madison County, Texas. Cowan was not hired or employed by the Company, but appears to have been working as a subcontractor for the Company's contract gauger/pumper. The Company entered into an agreement with the widow of James Cowan not to remove or alter the existing condition of certain equipment that may have been involved in the incident.

Regulatory and environmental contingencies

        The Company, as an owner and operator of oil and natural gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and natural gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. The Company maintains insurance coverage that it believes is customary in the industry, although it is not fully insured against all environmental risks.

        The Company is not aware of any environmental claims existing as of December 31, 2005, which would have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or that past non-compliance with environmental laws will not be discovered on the Company's properties.

Note 9—Successor—Members' Equity

        The holders of all of the TDC Notes contributed their TDC Notes to the Limited Partner in exchange for issuance of Class A common units of the Limited Partner, based on the proportionate amount of TDC Notes contributed. Each holder of a $1,000 TDC Note was entitled to a single Class A common unit of the Limited Partner pursuant to the rights, preferences and limitations set forth in the Amended and Restated Limited Liability Company Agreement of the Limited Partner ("LLC Agreement") dated as of September 30, 2004. As of December 31, 2004 and 2005, the Limited Partner had 118,125 units authorized and issued. Each holder of Class A common units of the Limited Partner is a Member in the Limited Partner. No Member by virtue of having the status of a Member has any management power over the business and affairs of the Limited Partner.

        The Limited Partner is managed by a Board of Managers as provided in the LLC Agreement. The Board of Managers consists of five members. Each holder of 20% or more of the Class A common units outstanding has the right to designate the greater of one Manager or the equivalent of one-fifth

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of the total number of Managers for each 20% of the common units held. The number of Managers may be increased or decreased from time to time by vote of the Board. On December 2, 2004, a resolution of the Board of Managers approved a reduction of the required number of Managers to four.

        The Limited Partner owns a 100% interest in the General Partner. Further, the Limited Partner owns a 99.999% interest in each of the Subsidiaries. The business and affairs of the General Partner are managed under the direction of a Board of Managers consisting of the same four individuals constituting the Board of Managers of the Limited Partner. The General Partner owns a .001% interest in each of the Subsidiaries. The General Partner directs the business and affairs of the Subsidiaries.

Note 10—Predecessor—Capital Stock

        On June 13, 2001, the Predecessor increased its authorized share capital to 445,000 shares of class A common stock and 65,000 shares of class B common stock. The Predecessor also effected a 238.333:1 stock split of its class A common stock. The consolidated financial statements give retroactive effect to the stock split for all periods presented. In connection with the stock split, the par value of the class A common stock decreased from $1.00 to $0.01 per share. The par value of the class B common stock is $0.01. The Predecessor's confirmed Plan cancels any and all issued and outstanding Class A and B common stock (see Note 2).

Note 11—Supplemental Oil and Natural Gas Information (UNAUDITED)

        The following information concerning the Company's natural gas and oil operations has been provided pursuant to Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities. The Company's oil and natural gas producing activities are conducted onshore within the continental United States. The Predecessor's activities were conducted onshore within the continental United States and offshore Texas. The evaluations of the oil and natural gas reserves at December 31, 2003, December 31, 2004 and December 31, 2005 were estimated by independent petroleum reserve engineers. The evaluations of the oil and natural gas reserves at September 30, 2004 were estimated using the December 31 independent petroleum reserve engineer estimates updated for internal production data.

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Capitalized Costs of Oil and Natural Gas Properties

        For all periods presented, all of the Predecessors' and Successors' properties were evaluated and included in the amortization base (in thousands).

    Successor

 
  As of December 31,
 
 
  2004
  2005
 
Properties subject to amortization—total capitalized costs   $ 124,020   $ 144,160  
Accumulated depletion and amortization     (1,686 )   (12,241 )
   
 
 
    $ 122,334   $ 131,919  
   
 
 

    Predecessor

 
  As of
December 31,
2003

  As of
September 30,
2004

 
Properties subject to amortization—total capitalized costs   $ 149,800   $ 150,655  
Accumulated depletion and amortization     (63,714 )   (67,759 )
   
 
 
    $ 86,086   $ 82,896  
   
 
 

Oil and Natural Gas Related Costs

    Successor

        The following table sets forth information concerning costs incurred related to the Successor's oil and natural gas property acquisition, exploration and development activities in the United States for the period from Inception to December 31, 2004 and for the year ended December 31, 2005 (in thousands):

 
  Inception to December 31, 2004
  Year ended
December 31,
2005

 
Property acquisition—proved   $ 122,811 (1) $  
Development costs     1,210     23,389 (2)
Proceeds from sales         (3,250 )
   
 
 
    $ 124,021   $ 20,139  
   
 
 

(1)
Includes $7,242 of asset retirement costs resulting from the Acquisition.

(2)
Includes asset retirement costs of $1,258, relating to new obligations incurred during the period, revisions to estimates and deletions for wells sold.

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    Predecessor

        The following table sets forth information concerning costs incurred related to the Predecessor's oil and natural gas property acquisition, exploration and development activities in the United States for the year ended December 31, 2003 and for the nine months ended September 30, 2004 (in thousands):

 
  Year ended
December 31,
2003

  Nine Months
ended
September 30, 2004

 
Property acquisition—proved   $   $  
Less—proceeds from sales of properties     (301 )   (20 )
Development costs(1)     18,796     874  
   
 
 
    $ 18,495   $ 854  
   
 
 

(1)
Includes asset retirement costs relating to new obligations incurred during the period and revisions to estimates. The total asset retirement costs included were $14,082 and $(52) for the year ended December 31, 2003 and the nine months ended September 30, 2004, respectively. Asset retirement costs incurred during 2003 include $12,641 related to the adoption of SFAS 143 on January 1, 2003.

Estimated Net Quantities of Natural Gas and Oil Reserves

    Successor

        The following table sets forth the Successor's net proved oil and natural gas reserves at December 31, 2005 and the changes in net proved oil and natural gas reserves for the period from Inception to December 31, 2004 and for the year ended December 31, 2005.

 
  Oil (Mbbls)
  Gas (Mmcf)
 
Proved reserves:          
  Acquisition from TDC on September 30, 2004   14,133   77,948  
  Revisions of previous estimates   202   2,993  
  Production   (187 ) (428 )
   
 
 
Balance, December 31, 2004   14,148   80,513  
  Extensions, discoveries, and improved recoveries   379   26,812  
  Revisions of previous estimates   1,235   (2,369 )
  Sales of reserves in place   (313 )  
  Production   (775 ) (4,854 )
   
 
 
Balance, December 31, 2005   14,674   100,102  
   
 
 
Proved developed reserves at December 31, 2004   12,653   18,757  
   
 
 
Proved developed reserves at December 31, 2005   12,819   28,557  
   
 
 

        Of the Successor's total proved reserves as of December 31, 2004 and 2005, approximately 53% and 54%, respectively, were classified as proved developed producing, 4% and 2%, respectively, were

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classified as proved developed non-producing and 43% and 44%, respectively, were classified as proved undeveloped. All of the Successor's reserves are located in the continental United States.

    Predecessor

        The following table sets forth the Predecessor's net proved oil and natural gas reserves at December 31, 2003 and September 30, 2004 and the changes in net proved oil and natural gas reserves.

 
  Oil (Mbbls)
  Gas (Mmcf)
 
Proved reserves:          
Balance, December 31, 2002   16,935   85,662  
  Extensions, discoveries, and improved recoveries   25   3,016  
  Revisions of previous estimates   (1,442 ) (1,792 )
  Production   (742 ) (3,664 )
   
 
 
Balance, December 31, 2003   14,776   83,222  
  Production   (545 ) (1,985 )
   
 
 
Balance, September 30, 2004   14,231   81,237  
   
 
 
Proved developed reserves at December 31, 2003   13,275   24,719  
   
 
 
Proved developed reserves at September 30, 2004   12,730   22,734  
   
 
 

        Of the Predecessor's total proved reserves as of December 31, 2003 and September 30, 2004, approximately 54% and 52%, respectively, were classified as proved developed producing, 7% and 7%, respectively, were classified as proved developed non-producing and 39% and 41%, respectively, were classified as proved undeveloped. All of the Predecessor's reserves are located in the continental United States.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

        The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by the Statement of Financial Accounting Standards No. 69, is an attempt to present the information in a manner comparable with industry peers.

        The information is based on estimates of proved reserves attributable to the Company's or the Predecessor's interest in oil and natural gas properties as of December 31 (or September 30) of the years presented. The December 31 estimates were prepared by independent petroleum engineers. Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates as of September 30, 2004 were developed using December 31 estimates from independent petroleum reserve engineers updated for internal production and pricing data and operating and development costs during the period.

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        The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

        (1)   Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on period-end economic conditions.

        (2)   The estimated future cash flows are compiled by applying period-end prices of crude oil and natural gas relating to the Company's proved reserves to the period-end quantities of those reserves.

        (3)   The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on period-end economic conditions.

        (4)   Future income tax expenses are based on period-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company's proved oil and natural gas reserves.

        (5)   Future net cash flows are discounted to present value by applying a discount rate of 10%.

        The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

        The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows and does not include cash flows associated with hedges outstanding at each of the respective reporting dates (in thousands).

    Successor

 
  As of December 31,
 
 
  2004
  2005
 
Future cash inflows   $ 1,078,704   $ 1,684,326  
Future production costs     (348,127 )   (509,798 )
Future development costs     (77,727 )   (93,302 )
Future income taxes     (195,966 )   (355,107 )
   
 
 
Future net cash flows     456,884     726,119  
10% annual discount for estimated timing of cash flows     (236,440 )   (351,555 )
   
 
 
Standardized measure of discounted future net cash inflows   $ 220,444   $ 374,564  
   
 
 

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    Predecessor

 
  As of
December 31,
2003

  As of
September 30,
2004

 
Future cash inflows   $ 948,078   $ 1,086,438  
Future production costs     (314,924 )   (302,699 )
Future development costs     (79,782 )   (78,856 )
Future income taxes     (174,696 )   (232,513 )
   
 
 
Future net cash flows     378,676     472,370  
10% annual discount for estimated timing of cash flows     (186,622 )   (233,525 )
   
 
 
Standardized measure of discounted future net cash inflows   $ 192,054   $ 238,845  
   
 
 

        The following table summarizes changes in the standardized measure of discounted future net cash flows (in thousands).

    Successor

 
  As of December 31,
 
 
  2004
  2005
 
Beginning of period   $ 214,084   $ 220,444  
Revisions to previous estimates     9,306     14,842  
Changes in prices and production costs     (24,022 )   142,596  
Changes in future development costs     15     17,775  
Development costs incurred during the period     1,210     22,131  
Extensions, discoveries and improved recovery, net of related costs         85,639  
Sales of oil and natural gas, net of production costs     (6,525 )   (59,962 )
Accretion of discount     27,822     30,776  
Net change in income taxes     28,232     (86,512 )
Sales of reserves in place     (4,156 )    
Purchases of reserves in place          
Production, timing and other     (25,522 )   (13,165 )
   
 
 
  End of period   $ 220,444   $ 374,564  
   
 
 

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    Predecessor

 
  As of
December 31,
2003

  As of
September 30,
2004

 
Beginning of period   $ 166,196   $ 192,054  
Revisions to previous estimates     (18,765 )    
Changes in prices and production costs     36,081     85,805  
Changes in future development costs     7,488      
Development costs incurred during the period     6,154     874  
Extensions, discoveries and improved recovery, net of related costs     2,740     7,439  
Sales of oil and natural gas, net of production costs     (15,484 )   (19,461 )
Accretion of discount     24,167     35,436  
Net change in income taxes     (10,688 )   (29,384 )
Sales of reserves in place          
Purchases of reserves in place          
Production, timing and other     (5,835 )   (33,918 )
   
 
 
  End of period   $ 192,054   $ 238,845  
   
 
 

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GLOSSARY OF TECHNICAL TERMS

3D seismic   Geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.

Anticline

 

An arch-shaped fold in rock in which rock layers are upwardly convex.

Bbl

 

One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbon.

Bcf

 

One billion cubic feet of natural gas.

Bcfe

 

One billion cubic feet of natural gas equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

BOE

 

One stock tank barrel of oil equivalent, using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

Btu

 

British thermal unit, the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion

 

The installation of permanent equipment for the production of oil or natural gas.

Condensate

 

Hydrocarbons which are in a gaseous state under reservoir conditions but which become liquid at the surface and may be recovered by conventional separators.

/d

 

Per day.

Developed acreage

 

The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development drilling or development wells

 

Drilling or wells drilled within the proved area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, to the depth of a stratigraphic horizon known to be productive.

Dry well

 

A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well.

Exploitation and development activities

 

Drilling, facilities and/or production-related activities performed with respect to proved and probable reserves.

Exploration activities

 

The initial phase of oil and natural gas operations that includes the generation of a prospect and/or play and the drilling of an exploration well.
     

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Exploration well

 

A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Finding and development costs

 

Capital costs incurred in the acquisition, exploration, development and revisions of proved oil and natural gas reserves divided by proved reserve additions.

Gross acres or gross wells

 

The total acres or wells, as applicable, in which a working interest is owned.

Infill drilling

 

Drilling of an additional well or wells below existing spacing to more adequately drain a reservoir.

Injection well

 

A well in which water is injected, the primary objective typically being to maintain reservoir pressure.

MBbl

 

One thousand barrels.

MBOE

 

One thousand BOEs.

Mcf

 

One thousand cubic feet of natural gas. For the purposes of this prospectus, this volume is stated at the legal pressure base of the state or area in which the reserves are located and at 60 degrees Fahrenheit.

Mcfe

 

One thousand cubic feet of natural gas equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.

MMcf

 

One million cubic feet of natural gas. For the purposes of this prospectus, this volume is stated at the legal pressure base of the state or area in which the reserves are located and at 60 degrees Fahrenheit.

MMBbl

 

One million barrels.

MMBOE

 

One million BOEs.

MMBtu

 

One million British thermal units.

Natural gas liquids

 

Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Net acres or net wells

 

The gross acres or wells, as applicable, multiplied by the working interest owned.

NYMEX

 

The New York Mercantile Exchange.

Oil

 

Crude oil, condensate and natural gas liquids.

Pay zone

 

A geological deposit in which oil and natural gas is found in commercial quantities.

Producing well or productive well

 

A well that is producing oil or natural gas or that is capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
     

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Proved developed non-producing reserves

 

Proved developed reserves that do not qualify as proved developed producing reserves, including reserves that are expected to be recovered from (i) completion intervals that are open at the time of the estimate, but have not started producing, (ii) wells that are shut-in because pipeline connections are unavailable or (iii) wells not capable of production for mechanical reasons.

Proved developed reserves

 

This term means "proved developed oil and gas reserves" as defined in Rule 4-10(a)(3) of SEC Regulation S-X, and refers to reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved developed reserves to production ratio

 

The ratio of proved developed reserves to total net production for the preceding 12 months.

Proved developed producing reserves

 

Reserves that are being recovered through existing wells with existing equipment and operating methods.

Proved reserves or proved oil and natural gas reserves

 

This term means "proved oil and gas reserves" as defined in Rule 4-10(a)(2) of SEC Regulation S-X and refers to the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved reserves to production ratio

 

The ratio of total proved reserves to total net production for the preceding 12 months or other specified period.

Proved undeveloped reserves

 

This term is defined in Rule 4-10(a)(4) of SEC Regulation S-X and refers to reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

PV-10

 

The present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using prices and costs as of the date of estimate without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and income taxes, and discounted using an annual discount rate of 10%. See page 13 of this prospectus.

Recompletion

 

The completion for production of an existing wellbore in a different formulation or producing horizon, either deeper or shallower, from that in which the well was previously completed.
     

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Reserve life

 

The estimated productive life of a proved reservoir based upon the economic limit of such reservoir producing hydrocarbons in economic quantities, assuming certain price and cost parameters. For purposes of this prospectus, reserve life is determined on a BOE basis by dividing the estimated proved reserves and revisions of previous estimates, excluding property sales, at the end of the year by the oil and natural gas volumes produced during the year.

Secondary recovery

 

The second stage of hydrocarbon production during which an external fluid such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore.

Shut-in

 

A well suspended from production or injection but not abandoned.

Undeveloped acreage

 

The number of acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved oil and natural gas reserves.

Waterflood

 

A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil.

Working interest

 

The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production, subject to all royalties, overriding royalties and other burdens, all costs of exploration, development and operations and all risks in connection therewith.

Workover

 

Remedial operations on a well conducted with the intention of restoring or increasing production from the same zone, including by plugging back, squeeze cementing, reperforating, cleanout and acidizing.

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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

        The following is a list of estimated expenses in connection with the issuance and distribution of the securities being registered:

SEC registration fee   $ 43,068
NASD filing fee     40,750
New York Stock Exchange listing fee     150,000
Printing expenses     600,000
Legal fees and expenses     900,000
Accounting fees and expenses     400,000
Engineering fees and expenses     300,000
Transfer agent fees     3,500
Blue sky fees and expenses     5,000
Miscellaneous     57,682
   
Total   $ 2,500,000
   

Item 14. Indemnification of Directors and Officers

        Section 145 of the Delaware General Corporation Law, or DGCL, authorizes a corporation to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, other than an action by or in the right of the corporation, because such person is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or other enterprise, against expenses, including attorneys' fees, judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reason to believe his conduct was unlawful. Similar indemnity is authorized for such persons against expenses, including attorneys' fees, actually and reasonably incurred in defense or settlement of any such pending, completed or threatened action or suit by or in the right of the corporation if such person acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and provided further that, unless a court of competent jurisdiction otherwise provides, such person shall not have been adjudged liable to the corporation. Any such indemnification may be made only as authorized in each specific case upon a determination by the stockholders or disinterested directors that indemnification is proper because the indemnitee has met the applicable standard of conduct. Article 10 of our certificate of incorporation generally provides that we will indemnify our directors and officers and certain other persons to the extent permitted by the DGCL. In addition, we have entered into an indemnification agreement with each of our directors, and an employment agreement with certain of our officers, pursuant to which we have agreed, in general, to indemnify those persons to the extent permitted by the DGCL.

        Section 145 of the DGCL also authorizes a corporation to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or enterprise, against any liability asserted against him and incurred by him in any such capacity, or arising out of his status as such, whether or not the corporation would otherwise have the power to indemnify him. We maintain policies insuring our and our subsidiaries' officers and directors

II-1



against certain liabilities for actions taken in such capacities, including liabilities under the Securities Act of 1933, as amended.

        As permitted by the DGCL, Article 9 of our certificate of incorporation eliminates in certain circumstances the monetary liability of our directors for a breach of their fiduciary duty as directors. These provisions do not eliminate the liability of a director:

    for a breach of the director's duty of loyalty to us or our stockholders;

    for acts or omissions by the director not in good faith;

    for acts or omissions by the director involving intentional misconduct or a knowing violation of law;

    under Section 174 of the DGCL, which relates to the declaration of dividends and purchase or redemption of shares in violation of the DGCL; and

    for any transaction from which the director derived an improper personal benefit.

Item 15. Recent Sales of Unregistered Securities

        On December 20, 2004, we sold $150.0 million in aggregate principal amount of our 8.75% senior notes due 2011 in a private placement. The notes were sold to Lehman Brothers Inc. and Harris Nesbitt Corp. (now BMO Capital Markets Corp.), as initial purchasers, in a transaction exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of that act. The initial purchasers resold the notes to (i) "qualified institutional buyers," as that term is defined in Rule 144A under the Securities Act and (ii) non-U.S. persons in transactions outside the United States in reliance on Regulation S under the Securities Act. The notes were issued to the initial purchasers at 99.362% of par. See "Description of Indebtedness—Senior Notes." The notes were subsequently exchanged for substantially identical notes that were registered under the Securities Act pursuant to our Registration Statement on Form S-4/A filed on April 20, 2004.

        Between February 2005 and April 2006, we granted options to purchase a total of 4,253,662.5 shares of our common stock to our directors and certain members of management, in each case other than Timothy Marquez, our Chairman and CEO. See "Management—Stock Option Plans." The grant of the options was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of that act. The persons to whom options were granted represented their intention to acquire the options and underlying shares of common stock for investment only and not with a view to or for sale in connection with any unregistered distribution thereof. The grant of the options were made without general solicitation or advertising. In addition, the persons to whom options were granted had access to information concerning our company, including through our public filings with the SEC, comparable to the information that would have been provided in a registration statement had the grant of the options been registered.

Item 16. Exhibits and Financial Statement Schedules

    (a)
    Exhibits

        See the accompanying Exhibit Index.


    (b)
    Financial Statement Schedules

        All schedules are omitted because the required information is (i) not present, (ii) not present in amounts sufficient to require submission of the schedule or (iii) included in our financial statements.

II-2



Item 17. Undertakings

        The undersigned Registrant hereby undertakes:

            (a)   Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

            (b)   For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

            (c)   For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-3



SIGNATURES

        Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on this 30th day of October 2006.

    VENOCO, INC.

 

 

By:

/s/  
TIMOTHY M. MARQUEZ      
      Name: Timothy M. Marquez
      Title: Chairman and Chief Executive Officer

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on the dates set forth below.

Signature
  Title
  Date

 

 

 

 

 
/s/  TIMOTHY M. MARQUEZ      
Timothy M. Marquez
  Chairman and Chief Executive Officer (Principal Executive Officer)   October 30, 2006

*

David B. Christofferson

 

Chief Financial Officer (Principal Financial Officer)

 

October 30, 2006

*

Douglas J. Griggs

 

Chief Accounting Officer (Principal Accounting Officer)

 

October 30, 2006

*

J. Timothy Brittan

 

Director

 

October 30, 2006

*

J.C. McFarland

 

Director

 

October 30, 2006

*

Edward O'Donnell

 

Director

 

October 30, 2006

*

Eloy U. Ortega

 

Director

 

October 30, 2006

*

Joel L. Reed

 

Director

 

October 30, 2006

*

Glen C. Warren, Jr.

 

Director

 

October 30, 2006

*By:

 

/s/  
TIMOTHY M. MARQUEZ      
Timothy M. Marquez
Attorney-in-Fact

 

 

 

 

II-4



Exhibit Index

Exhibit
Number

  Exhibit
1.1   Form of Underwriting Agreement.*

2.1

 

Agreement and Plan of Merger, dated as of March 30, 2006, by and among TexCal Energy (LP) LLC, Venoco, Inc., Bicycle Acquisition Company, LLC and Member Rep LLC (incorporated by reference to Exhibit 2.1 to the Annual Report on Form 10-K of Venoco, Inc. filed on April 5, 2006).

3.1

 

Restated Certificate of Incorporation of Venoco, Inc. (incorporated by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on November 17, 2005).

3.2

 

Bylaws of Venoco, Inc. (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on November 17, 2005).

4.1

 

Specimen stock certificate.**

4.2

 

Indenture, dated as of December 20, 2004, by and among Venoco, Inc., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 of Venoco, Inc. filed on March 31, 2005).

5.1

 

Form of Legal Opinion of Davis Graham & Stubbs LLP.**

10.1

 

Second Amended and Restated Credit Agreement, dated as of March 30, 2006, by and among Venoco, Inc. and Bank of Montreal, as Administrative Agent and Lead Syndication Agent, Harris Nesbitt Corp., as Lead Arranger, Credit Suisse Securities (USA) LLC and Lehman Brothers Inc., as Co-Arrangers, and Credit Suisse, Cayman Islands Branch and Lehman Commercial Paper Inc., as Co-Syndication Agents and Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to the Annual Report on Form 10-K of Venoco, Inc. filed on April 5, 2006).

10.1.1

 

First Amendment to the Second Amended and Restated Credit Agreement, dated as of May 2, 2006, by and among Venoco, Inc., the Guarantors identified therein, Bank of Montreal, as Administrative Agent, Credit Suisse, Cayman Islands Branch and Lehman Commercial Paper Inc., as Co-Syndication Agents, and Fortis Capital Corp., as Documentation Agent.**

10.1.2

 

Second Amendment to the Second Amended and Restated Credit Agreement, dated as of October 25, 2006, by and among Venoco, Inc., the Guarantors identified therein, Bank of Montreal, as Administrative Agent, Credit Suisse, Cayman Islands Branch and Lehman Commercial Paper Inc., as Co-Syndication Agents, and Fortis Capital Corp., as Documentation Agent.

10.2

 

Amended and Restated Term Loan Agreement, dated as of April 28, 2006, by and among Venoco, Inc., the Guarantors identified therein, Credit Suisse, Cayman Islands Branch, as Administrative Agent, Credit Suisse Securities (USA) LLC and Lehman Brothers Inc., as Joint Lead Arrangers, Harris Nesbitt Corp., as Co-Arranger, and Lehman Brothers Inc., as Syndication Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Venoco, Inc. filed on May 4, 2006).

10.3

 

Collateral Trust Agreement, dated as of March 30, 2006, by and between Venoco, Inc. and Credit Suisse, Cayman Islands Branch, as Administrative Agent and Collateral Trustee (incorporated by reference to Exhibit 10.3 to the Annual Report on Form 10-K of Venoco, Inc. filed on April 5, 2006).
     


10.4

 

Contract of Affreightment, dated as of March 13, 1998, by and between Public Service Marine Inc. and Venoco, LLC (incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S-4 of Venoco, Inc. filed on March 31, 2005).

10.4.1

 

First Amendment to Contract of Affreightment, by and between Public Service Marine Inc. and Venoco, Inc. (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-4/A of Venoco, Inc. filed on April 20, 2005).

10.5

 

Platform Agreement, dated as of March 1, 2006, by and between Venoco, Inc. and Clearwater Port, LLC (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K of Venoco, Inc. filed on April 5, 2006).

10.6

 

Purchase and Sale Agreement, dated as of December 3, 2004, by and among Venoco, Inc. and Members of Marquez Energy LLC (incorporated by reference to Exhibit 10.7 to the Registration Statement on Form S-4 of Venoco, Inc. filed on March 31, 2005).

10.6.1

 

Amendment to Sales Agreement, dated March 21, 2005, by and among Venoco, Inc. and Members of Marquez Energy, LLC (incorporated by reference to Exhibit 10.8 to the Registration Statement on Form S-4 of Venoco, Inc. filed on March 31, 2005).

10.7

 

Venoco, Inc. 2000 Stock Incentive Plan (incorporated by reference to Exhibit 10.12 to the Registration Statement on Form S-4 of Venoco, Inc. filed on March 31, 2005).

10.7.1

 

Form of Non-Qualified Stock Option Agreement for Non-Employee Directors Pursuant to the 2000 Stock Incentive Plan (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on November 17, 2005).

10.7.2

 

Form of Non-Qualified Stock Option Agreement for Non-Executive Officer Employees Pursuant to the 2000 Stock Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on November 17, 2005).

10.7.3

 

Form of Amendment to Nonqualified Stock Option Agreement Pursuant to the 2000 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Venoco, Inc. filed on June 12, 2006).

10.7.4

 

Form of Bonus Payment Agreement Relating to the 2000 Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Venoco, Inc. filed on June 12, 2006).

10.8

 

Venoco, Inc. Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Venoco, Inc. filed on May 12, 2006).

10.8.1

 

Form of Non-Qualified Stock Option Agreement Pursuant to the 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.2 the Current Report on Form 8-K of Venoco, Inc. filed on May 12, 2006).

10.9

 

Employment Agreement, dated as of May 4, 2005, by and between Venoco, Inc. and Timothy Marquez (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on May 16, 2005).

10.10

 

Employment Agreement, dated as of January 25, 2005, by and between Venoco, Inc. and William Schneider (incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-4 of Venoco, Inc. filed on March 31, 2005).

10.11

 

Non-Qualified Stock Option Agreement, dated as of May 4, 2005, by and between Venoco, Inc. and William Schneider (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on May 16, 2005).
     


10.12

 

Employment Agreement, dated as of May 4, 2005, by and between Venoco, Inc. and David Christofferson (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on May 16, 2005).

10.13

 

Non-Qualified Stock Option Agreement, dated as of May 4, 2005, by and between Venoco, Inc. and David Christofferson (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on May 16, 2005).

10.14

 

Employment Agreement, dated as of May 4, 2005, by and between Venoco, Inc. and Terry Anderson (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on May 16, 2005).

10.15

 

Non-Qualified Stock Option Agreement, dated as of May 4, 2005, by and between Venoco, Inc. and Terry Anderson (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on May 16, 2005).

10.16

 

Employment Agreement, dated as of August 15, 2005, by and between Venoco, Inc. and Mark DePuy (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on November 17, 2005).

10.17

 

Non-Qualified Stock Option Agreement, dated as of August 15, 2005, by and between Venoco, Inc. and Mark DePuy (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Venoco, Inc. filed on November 17, 2005).

10.18

 

Form of Amendment to Employment Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Venoco, Inc. filed on July 12, 2006).

10.19

 

Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Venoco, Inc. filed on October 31, 2005).

10.20

 

Registration Rights Agreement by and between Venoco, Inc. and the Marquez Trust (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Venoco, Inc. filed on August 31, 2006).

10.21

 

Consulting Agreement, dated as of January 23, 2006, by and between Venoco, Inc. and Edward O'Donnell (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Venoco, Inc. filed on January 23, 2006).

10.22

 

Indemnity and Guaranty Agreement, dated as of March 22, 2006, by the Marquez Trust in favor of Venoco, Inc. (incorporated by reference to Exhibit 10.29 to the Annual Report on Form 10-K of Venoco, Inc. filed on April 5, 2006).

10.23

 

Assignment and Subordination of Master Lease and Consent of Master Tenant, dated as of December 9, 2004, by and among 6267 Carpinteria Avenue, LLC, Venoco, Inc. and German American Capital Corporation (incorporated by reference to Exhibit 10.30 to the Annual Report on Form 10-K of Venoco, Inc. filed on April 5, 2006).

10.24.1

 

Ground Lease, dated as of August 29, 2006, by and between Venoco, Inc. and Carpinteria Bluffs, LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Venoco, Inc. filed on August 31, 2006).

10.24.2

 

Development Agreement, dated as of August 29, 2006, by and between Venoco, Inc. and Carpinteria Bluffs, LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Venoco, Inc. filed on August 31, 2006).

10.24.3

 

Dividend Distribution Agreement, dated as of August 29, 2006, by and among Venoco, Inc., the Marquez Trust and Carpinteria Bluffs, LLC (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Venoco,  Inc. filed on August 31, 2006).
     


21.1

 

Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to the Annual Report on Form 10-K of Venoco, Inc. filed on April 5, 2006).

23.1

 

Consent of Deloitte & Touche LLP.

23.2

 

Consent of Netherland, Sewell & Associates, Inc.**

23.3

 

Consent of Ryder Scott Company, L.P.**

23.4

 

Consent of DeGolyer & MacNaughton.

23.5

 

Consent of BDO Seidman, LLP.

23.6

 

Consent of Davis Graham & Stubbs LLP (included in Exhibit 5.1).

24.1

 

Power of Attorney.**

*
To be filed by amendment.
**
Previously filed.