Photo by Robert Goodell. Management Overview December 6, 2007

Transcription

1 Photo by Robert Goodell Management Overview December 6, 2007

2 Cautionary Statement Regarding Forward Looking Information Statements included in this presentation, other than statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of Venoco, Inc. ( Venoco or the Company ) cautions that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from those Venoco expects include changes in natural gas and oil prices, the timing, and cost of planned capital expenditures, timing of permits and/or approvals, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, the availability and cost of gathering and transportation facilities and transportation arrangements, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as the Company s ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting Venoco s business. More information about the risks and uncertainties relating to Venoco's forward-looking statements may be found in the Company s SEC filings, including under the heading "Risk Factors" in Venoco's Annual Report on Form 10-K for the year ended December 31, You should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Except as otherwise required by law, Venoco does not undertake any obligation to update any forward-looking or other statements as a result of new information, future events or otherwise. The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of unproved reserves which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. 2

3 About Venoco IPO November 17, 2006 Exchange/Ticker NYSE / VQ Market Cap $919 million (11/30/07) Shares outstanding million (9/30/07) 3

4 Company Overview Areas of Operations Portfolio Highlights Sacramento Basin Principal Fields Grimes Willows Proved Reserves (1) 98.6 MMBOE 58% Oil, 58% PD 3Q 2007 Daily Production 20.7 MBOE/d 3Q 07 to 3Q 06 22% growth Proved Reserve Life Index (1) 14.0 years % of Properties Operated ~96% Coastal California Principal Fields South Ellwood Sockeye Santa Clara West Montalvo Sacramento Basin Pro Forma Proved Reserves MMBOE (1) % Drilling Locations (as of 9/30/07) % 2008 Capex (Estimate) $130 MM Texas % 52 8% $70 MM Coastal California % 72 11% $35 MM 4 (1) Based on 12/31/06 reserve report, pro forma for 2007 acquisitions and 3Q year-to-date production. Total $235 MM

5 2008 Business Focus Organic production growth (projected 15-20% year-on-year) Sacramento Basin: Exploitation of extensive drilling/development inventory Hastings: Continue to grow conventional production & reserves Manvel: Field reactivation and increase fluid processing capacity W. Montalvo: Delineation wells, infill drilling, recompletions Santa Clara (platform Grace): Ramp up drilling and production Sockeye (platform Gail): Evaluate waterflood expansion Drive down operating and F & D costs Expand production and recovery South Ellwood (platform Holly): Advance lease extension project for anticipated start up in 2009 Hydraulic fracturing opportunities in the Sac Basin EOR and CO2 opportunities 5

6 Resource Rich Venoco s current project inventory provides for multiple opportunities to continue to increase proved reserves Identified Resource Potential Pro Forma Proved Reserves Probable Reserves S. Ellw ood Lease Extension Hastings Field CO 2 Manvel & W.Montalvo Probables & CO 2 Sacramento Basin Infill / Upside Monterey Shale Enhanced Recovery New Reservoirs 6

7 Proven Acquire & Exploit Track Record Based on acquisitions in South Ellwood (1997), Sockeye (1999) and Sacramento Basin (1996) 77% of acquired proved reserves remaining at 12/31/06 (MMBOE) Reserve Growth Value Creation 72.0 Proved 40.8 Proved PV10 $553 Proved 52.8 Cumulative Production 31.2 $36 Cumulative Free Cash $213 Flow 7 At Acquisition As of 12/31/06 (1) Cumulative production and free cash flow in the Sacramento Basin includes that from supplemental acreage purchased since (1) Acquisition Cost Cash Flow (1)

8 2007 Acquisitions Acquired the Manvel (TX; closed April 25 th ) and West Montalvo (CA; closed May 11 th ) fields Both fields in trends with existing Venoco operations $107 million purchase price for 9.7 MMBOE of proved reserves ($11.04/BOE) On February 13, 2007, Venoco closed on the last of three small Sacramento Basin acquisitions Negotiated transactions; added 3.2 MMBOE of proved reserves for $24 million ($7.56/BOE) TexCal Sacramento Basin and Texas fit well with existing operations & skill-set ($ in millions) Purchase Price + Adjustments (1) Proved Reserves (MMBOE)12/31/06 Net Acquisition Cost $ $10.08 / BOE Manvel Similar to the Hastings field Same Frio sands Less than 5 miles away Substantial upside via remedial field work Strong candidate for CO 2 flood West Montalvo Near Venoco s existing operations in Coastal California Shallow decline on existing production Very limited capital over the past decade Substantial portion of the field is undeveloped and un-delineated (1) Includes $37 million of net 2006 capex and divestitures and $50 million of Denbury option payments. 8

9 Experienced Management Team N ame Title P rior Affiliations E xperience Tim Marquez Chairman and CEO Founded Venoco in 1992, Unocal >25 Bill Schneider President Investment Banking, Unocal >20 Mark DePuy COO Unocal >25 Tim Ficker CFO Infinity Energy Resources, KPMG >15 Ed O'Donnell SVP, Coastal California Unocal >30 Brady McConaty VP, Texas Operations Tenneco >25 Kevin Morrato VP, Sacramento Basin General Atlantic, UMC >25 Greg Schrage VP, Asset Development Unocal, Texaco >25 9

10 Photo by Robert Goodell Core Areas of Operation

11 Sacramento Basin Summary 172 BCF proved (100% gas) (1) 85% (2) drilling success rate since beginning of 2004 Attractive realizations / low basis differentials 525 drilling locations (3) / 400 recompletion opportunities No downspacing restrictions Year-round drilling 2007 Activity Drill 130+ wells / 100 recompletions Continue to increase leasehold position 2008 Plans 110+ wells / 125 recompletions Capital expenditures of $130 million Sacramento Basin 186,707 net acres Principal Fields Grimes Willows New Wells E 2008E Rigs Proved Reserves: Drilling Locations: 28.7 MMBOE % of Total 81% of Total W ells Rigs (1) Based on 12/31/06 reserve report, pro forma for recent acquisitions. (2) In Willows and Grimes fields. (3) As of 9/30/07. 11

12 Sacramento Basin Upside Potential Forbes Formation Infill Development Drilling Program 80 acres 80 acres 80 acres O O O O O 20 acres 20 acres 20 acres 20 acres 40 acres 40 acres 40 acres 40 acres 2,800-8,900 ft. 1,500-3,500 ft. 12 Multiple stacked sands / isolated gas traps Majority of proved locations booked on 40- acre spacing; substantial upside through potential 20-acre infill program Low-cost recompletion program further enhances economics of each location Low-risk downspacing opportunity: of Venoco s existing wells, ~ 75% drain less than 20 acres, ~ 50% drain less than 10 acres.

13 Hastings Overview Cross Section of Frio Sands 2,800 2,600 2,400 2,200 2,000 1,800 Sands A B C D E F G H I Hastings Production, net BOPD TexCal Acquisition 45% Growth (1) ~4,648 net acres 374 wellbores 95 active / 279 idle (pre-acquisition) 152 active / 222 idle (post-acquisition) 1.2 Billion Bbls OOIP 500+ MMBOE remaining Producing reservoir - Frio (37 sand packages ) Significant - neglected/underfunded by prior owners Workovers & recompletions CO 2 Deep potential (no 3D over salt dome) 1, Dec- 05 Feb- 06 Apr- 06 May- 06 Jul- 06 Aug- 06 Oct- 06 Nov- 06 Jan- 07 (1) March 2006 to estimated November 2007 Feb- 07 Apr- 07 Jun- 07 Jul- 07 Sep- 07 Oct- 07 Proved Reserves: CO2 Upside: 13.6 MMBOE Up to 60 MMBOE 26% of Total Venoco 31% increase from 2005

14 Hastings Field CO 2 Project 14 Venoco entered into an option agreement with Denbury Resources in November 2006 $50 million payment for option Option can be exercised effective 11/1/08 or 11/1/09 Denbury pays Venoco PV-10% for Hastings reserves or VPP at Venoco s option Denbury carries Venoco on capital costs Denbury supplies CO2 Venoco retains a 2% override Venoco receives additional 22.3% reversionary interest following payout CO 2 recovery estimates: 10 20% of original oil in place (OOIP) Hastings OOIP ~1.2 billion barrels Hastings estimated recovery from CO 2 : MMBbls Phase I of the CO 2 flood has the potential to add 15 to 30 million barrels net to Venoco No CO 2 related reserves booked as of 12/31/06 Ultimate potential of 60 million barrels net to Venoco

15 Coastal California Summary Stable production & modest maintenance capex Massive fields with 3.6+ billion barrels OOIP 1% incremental recovery = 36 million bbls Significant barriers to entry Monterey Reservoir Unconventional/fractured shale 1,000 to 3,500 feet thick Multiple horizons & fault blocks West Montalvo acquisition expands footprint California Offshore Reserve History (Venoco ownership in red text.) MMBOE Proved Reserves: 44.4 MMBOE 45% of Total 12/31/03 12/31/04 12/31/05 12/31/06 Drilling Locations: 72 11% of Total 15

16 California Offshore Upside Potential South Ellwood Santa Clara Unit & W. Montalvo N Lease extension GRACE W. MONTALVO HOLLY GAIL DST 1982 ~4,000 BOE/D Significant infill development potential Monterey 2.1 Billion Barrels OOIP Low recovery to date (3% of OOIP) 1% incremental improvement = 20 MMBOE Lease extension with significant resource Project start up anticipated in 2009 Developed using existing infrastructure Sockeye Field (Platform Gail) Evaluate waterflood expansion Horizontal Monterey development Platform Grace Reactivation Drilling continues Ramp-up production in 2008 West Montalvo Active workover program Evaluate drilling opportunities 16

17 Photo by Robert Goodell Financial Overview

18 Financial Strategy Grow EBITDA and net asset value through low-risk development programs Fund higher growth assets with significant free cash flow from low decline legacy assets Preserve financial flexibility: Maintain undrawn revolver capacity Dry powder for opportunistic acquisitions Hedge to protect cash flow and capital budget and retain upside Approximately 70-80% of PDP hedged through 2010 (primarily collars) Intensify efforts to increase efficiency: Lower cash operating costs (LOE and G&A) per BOE produced Monetize non-core assets Drive down reserve replacement costs 18

19 Capital Expenditures Estimated 2008 Capex by Geographic Region Estimated 2008 Capex by Category ($ in millions) ($ in millions) Sacramento Basin 55% $130 Coastal California 30% $70 $35 Development Wells & W ellw ork 78% $185 Exploration 11% $25 $25 Facilities / Other 11% Texas 15% $235 million $235 million 2008 Drilling Schedule Coastal California Texas Sacramento Basin Total Development Wells Exploration Wells Total 2008 Wells Drilling Rigs Active

20 Summary Investment Highlights Long-lived, oil-levered asset base Low-risk, multi-year production growth ~650 drilling locations (5+ year inventory) Attractive F&D costs Sacramento Basin infill program has potential to double inventory 44% Production CAGR (1994 to year-end 2006) Geologically-proven resource in place offers visible potential for reserve growth Multiple, easily identifiable avenues of tangible net asset value accretion Selected opportunities have minimal net capital requirements Demonstrated ability to convert opportunity set to proved reserves and production Management / shareholder alignment Proven ability to create shareholder wealth 20

21 Photo by Robert Goodell Appendix

22 Sacramento Basin: Superior Realizations Enhance Economics Natural Gas Basis Differentials ($ per MMBtu) Based on $7.01 per MMBtu Henry Hub Average Nov price $0.01 $0.43 ($1.61) ($1.61) ($1.33) ($1.04) ($3.33) Rockies (Opal) San Juan Mid-Continent (NGPL) W. Texas (W aha) E. TX (Carthage) Sac. Basin (PG&E) Appalachia (Col Gas) Source: Platts Gas Daily Average Nov

23 Derivative Transactions Floor Cap Current Crude Oil Deliveries for Production BBLs/Day Weighted Avg Prices BBLs/Day Weighted Avg Prices Oct 1 - Dec 31, ,880 $ ,915 $ Jan 1 - Dec 31, ,100 $ ,100 $ Jan 1 - Dec 31, ,983 $ ,983 $ Jan 1 - Dec 31, ,150 $ ,150 $ Floor Cap Current Natural Gas Deliveries for Production MMBtu/Day Weighted Avg Prices MMBtu/Day Weighted Avg Prices Oct 1 - Dec 31, ,375 $ ,685 $ Jan 1 - Dec 31, ,650 $ ,097 $ Jan 1 - Dec 31, ,625 $ ,625 $ Jan 1 - Dec 31, ,900 $ ,900 $ Note: Location and quality differentials attributable to Venoco properties are not reflected in the prices shown. Positions shown are as of December 3,

24 Finding & Development Cost Review 2006 Organic Finding & Development Cost Survey ($ / BOE) $50.00 $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 Average = $20.51/BOE $12.28/BOE $10.00 $5.00 $0.00 KWK UPL XTO RRC BRY HAWK COG VQ FST DVN STR EOG SWN OXY PVA BBG MUR UNT NBL CHK EAC CMT EGN DPTR APA NFX PQ ME SM SGY DNR PPP EP THX BDE PXD XEC PXP BEXP SFY CRK EPL 24 Source: Wall Street Research. Note: Organic F&D costs including revisions.