This presentation includes forward-looking statements within the meaning of section 27A of the Securities Act of 1933 and Section 21E of the

Transcription

1 CLAYTON WILLIAMS ENERGY, INC. IPAA OGIS New York Conference April 12,

2 Regulatory Statements This presentation includes forward-looking statements within the meaning of section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of These statements are based on certain assumptions and analyses made by the Company in light of its experience, on general economic and business conditions and expected future developments, many of which are beyond the control of the Company. By their nature, forwardlooking statements involve risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. Important factors that could cause actual results to differ materially from those made in or implied by the forward-looking statements herein include, among others, risks experienced in exploration activities, the Company s ability to develop and replace reserves, the volatility of oil and natural gas prices, control by the Company s principal stockholder, uncertainty of the Company s liquidity, results of hedging transactions, uncertainties about estimates of reserves, the Company s ability to successfully integrate acquired operations into the Company s existing operations, drilling activity being less successful than expected, production variances from expectations, the availability of transportation facilities and other equipment, competition for properties, equipment, data and labor, changes in government regulation and risks associated with oil and gas drilling and production. Forward-looking statements are not guarantees of future performance and the Company's actual results, financial condition, liquidity and the development of its industry may differ materially from those indicated in or implied by such forward-looking statements. The Company s forward-looking statements speak only as of the date of such statements and the Company undertakes no obligations to update such statements. 2

3 Attendees Clayton W. Williams, Jr., President and CEO Mel G. Riggs, SVP of Finance and CFO Patti Hollums, Director of Investor Relations 3

4 Company Overview 4

5 Company Overview Headquartered in Midland, Texas Exploration, development and production in Texas, Louisiana and New Mexico Experienced team led by Clayton W. Williams, Jr. (50+ years in energy) Publicly traded since May 1993 (NASDAQ: CWEI) Proved Reserves as of 12/31/09 (SEC case): 33.6 MMBOE 62% crude oil, condensate and NGL s 82% located in oil-rich regions of the Permian Basin and Austin Chalk Market Data at March 31, 2010: Price per share: $34.98 Shares o/s: 12.1 million Market cap: $424.8 million Public float: $205.6 million 5

6 2009 Accomplishments Focused on development of oil reserves in the Permian Basin and Austin Chalk Locked-in vendor costs for 2 years Acquired control of drilling rigs (Desta Drilling) Made strategic pipe purchases at discounts to current market Protected cash flow through hedges 6

7 CWEI Core Resources Significant holdings in prime oil-producing regions Permian Basin Giddings Area 4Q 09 Avg Daily Net Production 7,021 BOE 4Q 09 Avg Daily Net Production 3,756 BOE Proved Reserves of 20 MMBOE 59% of Total Company Proved Reserves Permian Basin Midland, TX TX (Headquarters) Giddings Area Proved Reserves of 8.8 MMBOE 26% of Total Company Proved Reserves 188,000+ Net Acres 200,000+ Net Acres 7

8 Giddings Area Overview Plays include Austin Chalk, Cotton Valley, Bossier and Eagle Ford Shale Proven development success in Austin Chalk and Cotton Valley Exploration potential in Bossier and Eagle Ford formations 8

9 The Giddings Area - Exploiting Our Resources Began play drilling vertical wells in 1970 s; progressed to horizontal wells during 1990 s Pioneer and leader in horizontal drilling; more than 325 gross horizontal wells to date in the Austin Chalk In-fill drilling accelerated production and added reserves Began exploring Jurassic age formations in 1996; shot 3-D seismic; ultimate net reserves of 78 Bcf from Bossier sands Resumed exploring for Deep Bossier in 2005; 3 non-commercial wells to date, but significant potential remains; future drilling deferred for now Drilled Eagle Ford Shale well in 2010; currently evaluating production to determine economic viability 9

10 Austin Chalk Well Economics: Payout: 1.8 years; ROR: 53% (based on $80 oil and $4.50 gas) Net Reserves: 78.4 MBOE Net AFE Costs: $1.9 MM (100% WI) 100% working interest in most locations 4Q 2009 avg daily net production: 3,110 BOE Planned Activities: 30 proved and up to 50 possible in-fill development locations identified Step-out well to the southwest looks encouraging; may add up to 20 possible locations Additional secondary and tertiary water fracs available to accelerate production and add reserves Austin Chalk Development Program Eagleton Trivett #1 Burleson County, Texas Net Positions: 192,000 Net Acreage 10

11 Deep Bossier Trend Update 3 wells drilled (non-commercial) Conoco-Phillips Savell Field Encana/Leor Amoruso Field Geological data indicates nearby structure and trap potential Possible offset to Big Bill Simpson No. 1 to test top of structure in late 2010 or 2011 Big Bill Simpson No. 1 Margarita No. 1 Sunny Unit #1 Future drilling deferred until higher gas prices Continue to be optimistic about upside potential in this area Net Acreage 130,000 11

12 Permian Basin Overview 4Q 2009 Net Daily Production: 7,021 BOE 59% of year end reserves 200+ proven locations Several hundred probable & possible locations Long life reserves Primarily oil Vertical and horizontal wells Devonian, Pennsylvanian, Wolfcamp, Spraberry and San Andres Formations 4,000 11,500 foot wells Desta Drilling Rig #12 12

13 Permian Basin Clayton Williams, Jr. has roots in West Texas Had significant success in the 70 s and 80 s in Coyanosa, Vermejo, Rhoda Walker and Mi Vida fields Vast experience in both upstream & downstream operations Clajon Gas Company largest independent natural gas company in Texas before its sale in 1987 Strategic acquisition of Southwest Royalties in 2004 provided position in the Permian Basin Currently drilling in Wolfcamp/Spraberry and San Andres formations Planned operations in southeastern New Mexico 13

14 Andrews County Wolfberry Well Economics: Payout: 2.2 years; ROR: 42% (based on $80 oil and $4.50 gas) Net Reserves: 92.6 MBOE Net AFE Costs: $1.7 MM (100% WI) Current Net Daily Production: >1,500 BOE Planned Activities: Drill 104 wells in 2010 Drill 120 wells in 2011 What is a Wolfberry? A Wolfberry well is a well that commingles production from the Wolfcamp and Spraberry formations Net Positions: University Lands 6,500 (86% WI) Fee Acreage 5,600 (100% WI) Farm Out Acreage 3,200 (60% WI) 14

15 Fuhrman-Mascho Well Economics: Payout: 4 months; ROR: +100% (based on $80 oil and $4.50 gas) Net Reserves: 35.8 MBOE Net AFE Costs: $360,000 (90% WI) Planned Activities: 5 wells planned for 2010 Results to date: 37 wells currently producing approximately 600 BOE/d net 15

16 Loco Hills, New Mexico Well Economics: Payout: 21 months ROR: 66% Net Reserves: 28 MBOE Net AFE Costs: $417,000 (average WI) Planned Activities: History: 1996 Acquisition from Conoco 2000 Farm in from Phillips Petroleum Long Life Properties 25 vertical wells in Empire Field 18 in upper Yeso formation (infill drilling) 7 in lower Yeso formation (new development) 55%-100%WI Production: 4Q 09 avg daily net 400 BOE 16

17 Louisiana Overview North Louisiana 4Q 09 Avg Daily Net Production 1,755 BOE Terryville Ruston Proved Reserves of 3.2 MMBOE 9% of Total Company Proved Reserves Potential locations: 22 South Louisiana West Lake Washington 4Q 09 Avg Daily Net Production 2,295 BOE Fleur Proved Reserves of 1.2 MMBOE 4% of Total Company Proved Reserves Potential locations: 2 17

18 Whittier Main Field (Whittier, California) Abandoned by Chevron during 1991 Producing 900 BOPD before abandonment Approximately 60 MMBOE recovered prior to abandonment (gravity of 24 to 42 API) Recovery estimated at only 10% of oil in place from sandstone and shale source rock zones City of Whittier now owns mineral rights 1,280 acre lease awarded to Matrix Oil/CWEI Delineated oil zones from 800 feet to 8,000 feet 18

19 Whittier Main Field Puente Hills Whittier City 1 Mile Location of the City Lease 1280 acres in Green and Yellow Outline 19

20 Reserves & Financial Overview 20

21 Summary of proved reserves at December 31, 2009 By location Louisiana 13% Proved Reserves (MMBOE) Cotton Valley 3% Austin Chalk 23% Other 2% Permian Basin 59% 2007 By Production Mix Reserve Category 21

22 PV-10 Reserve Value December 31, 2009 ($ in millions) Avg Prices Oil $54.81 Gas $3.71 Oil $70.98 Gas $5.61 Oil $79.99 Gas $

23 2010 Exploration and Development Costs Planned for 2010 = $274.4 Million 23

24 Capitalization and Liquidity Capitalization ($ millions) December 31, /4% Senior Notes due 2013 $225.0 Secured bank credit facility, due May Total debt $395.0 Total equity Book capitalization $607.3 Liquidity ($ millions) December 31, 2009 Capacity Drawn Revolving credit facility $250.0 $170.0 Letters of credit 0.8 $170.8 Liquidity $

25 Summary of Operations (Dollars in millions, except per unit) EBITDAX.$ E $ Cash flow from operations. $ $ Production: Oil and NGL (MBbls).. 3,105 3,445 Natural gas (MMcf) 15,949 12,729 Total production (MBOE) 5,763 5,566 Operating metrics per BOE: Lease operations $ $ DD&A. $ $ G&A $ 3.59 $ Proved developed producing reserves (MBOE): Beginning of period. Additions.. Production.. End of period. Reserve replacement ratio ,754 9,620 (5,566) 31, % 25

26 Production Data 1, , Q 2010E 4Q 2010E MBOE 1,000 1, , Q 2010E 2Q 2010E Base Production Drilling Production 26

27 Summary of Hedges as of March 31, 2010 Swaps: Oil Bbls Production Period: 1st Quarter ,000 2nd Quarter ,000 3rd Quarter ,000 4th Quarter , ,656,000 3,860,000 Gas Price $76.70 $76.60 $76.40 $76.24 $84.38 MMBtu (a) 2,280,000 1,830,000 1,750,000 1,680,000 6,420,000 13,960,000 Price $6.80 $6.80 $6.80 $6.80 $7.07 (a) One MMBtu equals one Mcf at a Btu factor of 1,

28 Why Invest in CWEI? Focused on oil with reserves 62% oil at year end 2009; projected to grow to 70% by end of 2010 Capital budget for 2010 is 97% development drilling Stock currently trades at approximately 2 times 2010 projected cash flow With only 12.1 million shares outstanding, the Company offers a very attractive risk-reward profile 28

29 Appendix 29

30 Summary of Historical Financials Year ended December 31, ($ millions) Operations: Total revenue Growth % Cash Flow from Operations Margin % Capital Expenditures (a) $ % $ % $230.7 $ % $ % $372.7 $ % $ % $138.3 Balance sheet: Cash Long-term debt (b) Total equity Book capitalization $12.3 $452.7 $160.8 $613.5 $41.2 $366.0 $320.3 $686.3 $14.0 $395.0 $212.3 $607.3 (a) Oil and Gas Producing Activities (b) Includes Current Maturities 30

31 Cash Flow from Operations ($ in millions) $500 $382.0 $400 $300 $234.9 $200 $104.7 $100 $

32 Total Debt ($ in millions) $500.0 $452.7 $395.0 $366.0 $400.0 $300.0 $200.0 $100.0 $

33 Capital Expenditures ($ in millions) $400 $372.7 $300 $274.4 $230.7 $200 $138.3 $100 $ E 33

34 Production (MBOE) 7,000 5,982 6,226 5,763 6,000 5,566 5,000 4,000 3,000 2,000 1, E 34

35 2010 Guidance (a) Excludes amounts derived from Desta Drilling 35

36 Coverage Ratios 36

37 Computation of EBITDAX (a) EBITDAX represents income (loss) from continuing operations before noncontrolling interest, interest expense, income taxes, exploration costs, gain/loss on sales of assets and impairment of inventory, and non-cash items in our statement of operations, including depreciation, depletion and amortization, impairment of property and equipment, accretion of abandonment obligations, non-cash employee compensation and unrealized gain/loss on derivatives. EBITDAX provides useful information to investors as a measure commonly used by debt holders, industry analysts, lenders, ratings agencies and financial statement users to determine the ability of an entity to meet its interest obligations. EBITDAX calculations may vary among entities, so our computation of EBITDAX may not be comparable to EBITDAX or similar measures of other entities. EBITDAX is not a measure calculated in accordance with generally accepted accounting principles (GAAP). EBITDAX is reconciled to income (loss) from continuing operations as shown in the table above. Our EBITDAX measure should not be considered an alternative to net income, income before taxes, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP. 37

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