Looking Statements. Section 27A of the Securities Act of 1933 and Section 21E of the Securities. Forward

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1 NYSE:CRK

2 Forward Looking 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 Forward-looking statements give our current expectations or forecasts of future events. These statements include estimates of future natura al gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, budgeted capital expenditures and other anticipated cash outflows, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Factors that could cause actual results to differ materially from expected results are described under Risk Factors in our 2011 Form 10-K filed with the U.S. Securities and Exchange Commission. Our production forecasts are dependent upon many assumptions, including estimates of production de ecline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other forward-looking statemen ts are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. 2

3 rd Quarter Highlights Growing oil production helps to partially offset very weak natural gas prices Oil & Gas Sales - $117 million EBITDAX - $87 milli ion Cash Flow From Operations - $71 million ($1.47 per share) Net Loss - $26 million (56 per share) Strong oil production growth in the quarter Oil production increased 13% from the second quarter of 2012 Oil production up 238% from the third quarter of 2011 and now makes up 16% of total production compared to 4% in the third quarter of 2011 Natural gas production decreased 19% due to property sales and declines in Haynesville shale production Successful drilling program in out of 56 wells drilled were successful Strong results in Eag gle Ford shale and Wolfbone drilling program Improving liquidity Operating cash flow expected to cover 4 th quarter drilling expenditures Increasing oil production and improving natural gas prices expected to grow revenues and cash flow in 2013 Bank borrowing base increased to $570 million to fully cover nonconforming portion 3

4 Oil Production MBbls / day Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q MBbls (-23%) MBbls (-8%) Sold oil production estimated to be 2.4 MMBbls to 2.5 MMMbls (190 to 200%) MBbls (17%) Other Wolfbone Eagle Ford ,748 MBbls (255% over 2011) 1.9 4

5 Natural Gas Production MMcf / day Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q Bcf (13%) Bcf (13%) Bcf (31%) Bcf Sold Other Cotton Valley South Texas Haynesville (-4% over 2011) 2012 gas production estimated to be 81 Bcf to 82 Bcf (-11 to -9%) 5

6 Average Oil Price 3 rd Quarter Per Barrel Without Hedging With Hedging $ $97.09 $92.22 $92.22 $87.55 $ % increase over 2011 s third quarter 2011 Q Q3 NYMEX 2011 Q Q3 NYMEX 105% of NYMEX 68% Hedged 6

7 Aver rage Oil Price Nine Months Per Barrel Without Hedging With Hedging $ $99.63 $96.21 $96.21 $92.59 $ % increase over 2011 s first nine months 2011 Nine 2012 Nine Mos Mos NYMEX 2011 Nine 2012 Nine NYMEX Mos Mos 104% of NYMEX 72% Hedged 7

8 Oil Hedges Attractive oil hedge position to protect 2012 and 2013 capital programs As of September 30, 2012 Oil Swaps: Volume (Bbls/day) NYMEX price (Bbl) (a) 2012 Q4 5,000 $ ,000 $98.67 (a) The index price for the oil contracts are based on the NYMEX-West Texas Intermediate monthly average future prices. 8

9 Average Gas Price Per Mcf $4.09 $4.09 $2.46 $2.80 $2.37 $ % decrease from 2011 s third quarter 42% decrease from 2011 s first nine months 2011 Q Q3 NYMEX 2011 Nine Mos 2012 Nine Mos NYMEX 88% of NYMEX 92% of NYMEX 9

10 Oil & Gas Sales $ in millions $320 $332 2% decrease over 2011 s third quarter $119 $117 4% increase over 2011 s first nine months 2011 Q Q Nine Mos 2012 Nine Mos 14% 0il 57% 0il 14% 0il 54% 0il 10

11 EBITDAX $ in millions $246 $240 8% decrease from 2011 s second quarter $94 $87 2% decrease from 2011 s first nine months 2011 Q Q Nine Mos 2012 Nine Mos 11

12 Opera ating Cash Flow $ in millions $219 $199 $86 $71 17% decrease from 2011 s third quarter 9% decrease from 2011 s first nine months 2011 Q Q Nine 2012 Nine Mos Mos 12

13 Earnings $ in millions (e except per share amounts) $7.7 $1.3 $(26.0) $(29.4) 3 16 Unusual Items in third quarter: Pre Tax After Per Pre After Tax Share Tax Tax Per Share Loss on sale of properties/ JV costs $ (2.8) $ (1.8) $ (0.04) 04) $ - $ - $ - Gain on Sale of SGY Impairments (1.4) (0.9) (0.02) Total $ (4.2) $ (2.7) $ (0.06) $ 2.5 $ 1.6 $ 0.04 Unu usual Items in nine months ended Sept. 30: Pre Tax After Per Pre After Tax Share Tax Tax Per Share (56 ) 2011 Q Q Nine Mos Gain on sale of properties $ 24.3 $ 15.8 $ 0.34 $ - $ - $ - (63 ) Gain on Sale of SGY Nine Impairments (8.0) (5.2) (0.11) (9.8) (6.4) (0.14) Mos Early Extinguishment of Debt (1.1) (0.7) (0.02) Total $ 42.9 $ 27.9 $ 0.60 $ 21.3 $ 13.8 $

14 $0.90 $0.28 $0.28 $0.04 $0.06 $0.58 Costs per Mcfe $1..13 $1.06 $1.03 $0.97 $0.85 $0.79 Lifting $0.77 $0.31 $0.31 $0.32 $0.14 $0.13 $ $0.06 $0.26 $0.29 $0.16 $0.51 $0.58 $0.47 $0.64 $0.39 $ Q Q Q Q Q Q Q Lifting Production Taxes Transportation 14

15 Co osts per Mcfe $0.26 General & Administrative $0.21 $0.18 $0.20 $0.21 $0.22 $ Q Q Q Q Q Q Q Excludes Stock-based Compensation 15

16 Costs per Mcfe Depreciation, Depletion & Amortization $4.10 $3.59 $3.03 $3.12 $2.96 $3.07 $ Q 2Q 3Q 4Q 1Q 2Q 3Q 16

17 Drillin ng Expenditures $ in millions $443 $2 $124 $402 Excludes $53 million in 2011 and $24 million in 2012 for Acreage Costs $139 South Texas is net of $24 million of reimbursements from the Eagle Ford JV $318 $161 West tt Texas / Other South Texas $102 East Texas / North Louisiana

18 Ba alance Sheet As of Sept. 30, 2012 Cash and cash equivalents $ 3 Marketable securities (1) 15 Revolving Credit Facility ($850MM) 355 Borrowing Base $570 Availability ($ $) $215 Availability (%) 38% 8⅜% Senior Notes due ¾% Senior Notes due ½% Senior Note es due Total Debt 1,239 Shareholders' Equ uity 1,011 Total Capitalization $ 2,250 Total Debt / Capit talization 55% (1) Includes 600,000 shares of Stone Energy Corporation. 18

19 East Texas / North N Louisiana Region g Cotton Valley Haynesville Shale Cotton Valley Bossieer Shale Haynesville/Bossier Shale D ill d 7 wells ll ( nett ) to t date d t iin 2012 Drilled Reducing activity with low w natural gas prices Gross Acres 95,000 Net Acres 81,000 Resource R Potential 7 Tcfe 19

20 West Texas Region 91,000 gross (57,000 net) acres Over 900 net vertical locations targeting the Wolfbone play Total resource potential of 178,000 MBOE Horizontal development upside in the Wolfcamp shale 20

21 A CULBERSON COUNTY Geological Setting REEVES COUNTY WARD COUNTY F DEWEY LAKE SEA LEVEL 0 OCHOAN EVAPORITES RUSTLER SALADO 1,000 CASTILE ,000 DELAWARE SANDS 3,000 BELL CANYON 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 17,000 18,000 CHERRY CANYON BONE SPRING BRUSHY CANYON 1 ST BS LIME AND SAND WOLFCAMP 2 nd BS LIME AND SAND 3 rd BS LIME AND SAND WOLFCAMP SHALE TARGETS (A, B, MIDDLE, & LOWER) TOYAH AR RCH DELAWARE BASIN F PENNSYLVANIAN MISSISSIPPIAN DEVONIAN/SILURIAN ORDOVICIAN A PRECAMBRIAN 21

22 Wollfbone Activityy Trigger 40 #2 (166 BOE/day) BOE/d ) City of Pecos 13 #2 (197 BOE/day) Jesse James 4 #2 (511 BOE/day) Will Rogers 4 #1 (317 BOE/day) Bonanza State 25 #1 (396 BOE/day) Monroe 35 #1H (653 BOE/day) Wild Bill Hickock 205 #3 (173 BOE/day) Ponderosa State 25 #1 (511 BOE/day) Drilled 229 (21.1 net) wells to date in verticaal Wolfbone wells and 1 horizontal Wolfcamp shale well Averaage per well IP 370 BOE/day 22

23 Comstock s Wolfbone Wells Well 1 Pistola 186 #1 2 Balmorrea Ranch 41 #1 3 City of Pecos 15 #1 4 Bell 213 A #2 5 Monroe 28 #1 6 Pecos Bill 203 #1 7 Roy Rogers 21 #1 8 Monroe 39 #1 9 Bell 213 A #3 10 Capps 214 A#2 11 City of Pecos 16 #1 12 Doc Holiday 23 #1 13 Billy the Kid 31 #1 14 Wyatt Earp 22 #1 15 Bell 213 A #4 16 Wild Bill Hickock k 205 #1 17 Sky King 47 #1 18 Annie Oakley 23 #1 19 Paladin 43 #1 20 City of Pecos 13 #1 21 Monroe 28 #2 22 Dale Evans 196 #1 23 Jesse James 4 #1 24 Lone Ranger State 192 #1 25 Pistola 186 #2 26 Pat Garrett 38 #1 27 Sheldon State 3 #2 28 Buffalo Bill 9 #1 29 Trigger 40 #1 30 HSF State 3 #1 31 Gunsmoke 190 #1 32 Sky King 47 #2 33 Johnny Ringo 9 #1 34 Ponderosa State 25 #1 35 Monroe 35 #1H 36 Wild Bill Hickok 205 #3 37 Will Rogers 4 #1 38 Bonanza State 25 #1 39 City of Pecos 13 #2 40 Trigger 40 #2 41 Jesse James 4 #2 1st Production 24hr IP, BOEPD 30-day IP, BOEPD % of IP 90-day IP, BOEPD % of IP 5/14/ % % 9/23/ % % 11/9/ % % 1/14/ % % 1/15/ % % 3/20/ % % 4/14/ % % 4/26/ % % 5/21/ % % 5/26/ % 71 37% 6/29/ % % 7/19/ % % 8/11/ % % 9/3/ % % 10/10/ % % 11/21/ % % 11/22/ % % 12/18/ % % 1/24/ % 83 40% 1/24/ % 84 41% 2/21/ % % 3/10/ % % 3/13/ % % 3/29/ % % 4/5/ % 86 44% 4/23/ % % 5/4/ % 93 38% 5/10/ % % 5/14/ % % 5/21/ % % 6/9/ % % 7/6/ % 7/16/ % 8/10/ % 9/1/ % 7/27/ % 8/13/ % 8/16/ % 8/24/ % 9/22/ /14/ % % 23

24 Comstock k s Wolfbone Wells Buffalo Monroe Ponderosa Bill 23 Jessie James operated vertical Wolfbone wells p shale well 1 horizontal Wolfcamp Averaage per well IP 322 BOE/day 24

25 South Texas Region Atascosa Karnes Frio LaSalle McMullen Gross Acres 35,000 Net Acres 28,000 Wells 277 Gross EUR 500 MBOE Drilled 20 (13.9 net) wells to date in 2012 All horizontal Eagle Ford shale wells Average per well IP 662 BOE/day Resource 78 MMBOE* Potential *Net of Joint Venture and Royalties 25

26 Comstock s Eagle Ford Shale Wells Well County 1 NWR #1H Atascosa 2 RTH #1H McMullen 3 Coates A #1H Karnes 4 Carlson A #1H McMullenM 5 Swenson #1H McMullen 6 Hill #1H McMullen 7 Cutter Creek #1H McMullen 8 Forest Wheeler #1H McMullen 9 RTH A #1H McMullen 10 Jupe A#1H Atascosa 11 Hill A #1H McMullen 12 Hill B #4H McMullen 13 Hill #2H McMullen 14 Hill B #3H McMullen 15 Hill A #2H McMullen 16 Cutter Creek #2H McMullenM 17 Donnell A #1H McMullen 18 Gloria Wheeler B #1H McMullen 19 Gloria Wheeler A #1H McMullen 20 Schorp #3H LaSalle 21 Lucas A #1H Atascosa 22 Cortez B #1H LaSalle 23 Cortez A #1H McMullen 24 Cortez A #2H LaSalle 25 Cortez B #2H LaSalle 26 Carlson B #1H McMullen 27 Donnell B #1H McMullen 28 Lucas B #1H Atascosa 29 Lucas C #1H Atascosa 30 Haynes A #1H McMullen 31 DVR B #1H Atascosa 32 Donnell C #1H McMullen 33 Carlson C #1H McMullen 34 Hubberd #3H McMullen 35 Hubberd #A #1H McMullen 36 Hill #5H McMullen 37 Hill A #3H McMullen 38 Swenson #2H McMullen 39 Swenson C #1H McMullen 40 Hubberd #2H McMullen 41 Hubberd #1H McMullen 1st 24hr IP, 30-day IP, % of 90-day IP, % of Production BOEPD BOEPD IP BOEPD IP 11/18/ % % 12/3/ % % 2/4/ % % 2/25/ % % 4/13/2011 1, % % 7/3/2011 1, % % 8/7/ % % 8/12/ % % 8/27/ % % 10/3/ % % 11/1/2011 1, % % 11/3/ % % 11/8/ % % 11/15/ % % 11/18/2011 1, % % 12/9/ % % 12/9/ % % 12/14/2011 1, % % 12/15/2011 1, % % 2/28/ % % 3/1/ % % 3/30/ % % 4/3/ % % 4/4/ % % 4/4/ % % 4/10/ % % 4/10/ % % 4/15/ % % 4/17/ % % 5/25/ % % 6/22/ % % 7/6/ % % 7/7/ % % 7/11/ % % 7/11/ % % 8/18/ % 8/18/ % 8/22/ % 9/9/2012 1, % 9/18/ % 10/12/ % % 26

27 Comstock s Eagle E g Ford Shale Wells 3 Atascosa Karnes 31 Frio LaSalle McMullen Comp pleted 41 wells (35.5 net) A All horizontal wells Average g p per well IP 705 BOE/dayy 27

28 2012 Outlook Strong oil growth in 2012 Oil to comprise 15 to 18% of 2012 production and over 20% of production at the end of the year 93% of the net wells drilled in 2012 will be oil wells and 78% of the 2012 drilling budget will be spent on oil projects Oil focused Eagle Ford shale program expected to be largest contributor to production growth in 2012 Plan to drill 29 wells in oil window of the Eagle Ford shale Wolfbone program in West Texas has potential to fuel substantial growth in oil reserves and production in the longer term Adds low risk vertical oil focused drilling program Plan to drill 43 vertical and 4 horizontal wells in the Wolfbone field in West Texas in 2012 More horizontal wells planned for 2013 Low cost structure Comstock continues to industry Improved financial pr have one of the lowest overall costs structures in the ofile with 2012 transactions Reduced leverage with assets divestitures which generated $183 million in net proceeds Senior notes offering fr reed up over $200 million of the bank credit facility Utilizing an oil price hedging strategy in 2012 to protect the recent acquisition and our oil focused drilling program Eagle Ford joint venture allows accelerated drilling program starting in December