April 2010 Investor Presentation

Transcription

1 April 2010 Investor Presentation

2 CHK Overview The second largest producer of U.S. natural gas (post XOM/XTO acquisition) 4Q 09 natural gas production of bcf/d Most active driller in U.S. CHK is responsible for 1 of 8 gas wells being drilled in the U.S. 118 operated rigs currently, down from 158 in 8/08 (~25%); ~70 non-operated rigs & ~15 info only rigs; collector of ~20% of all daily drilling information generated in the U.S. (~25% in our areas of interest); ~91% of our operated rigs are in the Big 6 shale and Granite Wash plays Moving ~20 natural gas-focused rigs to oil and wet gas plays because of low gas prices Aggressively transitioning to oilier plays; goal is ~20% of total production from liquids Consistent production growth 20 consecutive years of sequential production growth Projecting increases of ~8-10% in 2010 and ~15-17% in 2011 to ~2.7 and ~3.1 bcfe/d, respectively (after curtailments and asset sales) Best assets in the industry ~14.6 tcfe of proved reserves at 12/09, targeting tcfe by 2012 (1)(2) ~65 tcfe of risked unproved resource potential (~177 tcfe of unrisked unproved resource potential) >10-year inventory of ~36,000 net drilling locations (2) BP, PXP, STO and TOT JV s confirm asset quality directly; XOM/XTO and APC/MITSY confirm indirectly Unparalleled inventory of U.S. onshore leasehold and 3D seismic 13.7 mm net acres of U.S. onshore leasehold and ~23.6 mm acres of 3D seismic data Data above incorporates: CHK s Outlook dated 2/17/10 Risk disclosure regarding unproved resource estimates appears on page 30 (1) Based on 10-Year average NYMEX strip pricing pro forma for Barnett JV; 14.3 tcfe at 12/31/09 using SEC pricing before Barnett JV (2) As of 12/31/09, and pro forma for Barnett JV 2

3 CHK Overview, Continued High quality U.S. shale asset base within the Big 6 #1 in Marcellus Shale; ~1,570,000 net acres #1 in Haynesville Shale; ~535,000 net acres #2 in Fayetteville Shale; ~455,000 net acres #2 in Barnett Shale; ~220,000 net acres (post Barnett JV) #1 in Bossier Shale; ~180,000 net acres Top 5 in Eagle Ford Shale; ~300,000 net acres (1) Advantageous joint venture arrangements $10.7 billion of value captured vs. cost basis of $2.7 billion $33 billion of remaining implied value based on JV terms ~$3 billion of remaining joint venture carry receivables Built-in finding cost advantages Able to add tcfe per year of new proved reserves (after replacing production) at <$1.50/mcfe per year for years to come Reserve maintenance cap-ex only ~25% of projected 2010 and 2011 operating cash flow Substantial scale and vertical integration advantages Strong hedging track record ~$4.4 billion in realized gains ) As of 4/8/2010 CHK has many unique competitive advantages in this tough economic environment unmatched asset quality, high returns, low finding and operating costs, great hedges and world class JV partners 3

4 CHK s Value Creation Process Through enhanced drilling technology, industry leading opportunity capture and unique value-adding JV sales of minority positions, CHK has increased its total resource base in the last 3 years by ~200% to ~80 tcfe (1) CHK should be able to grow its proved reserves by tcfe per year at <$1.50/mcfe for at least the next 5-10 years As a result, CHK will deliver very significant value creation for its investors. Here is a possible scenario for what CHK might look like just 3 years from now (2012): Production should average bcfe/d, an increase of 40-50% from 2009 levels Proved reserves should reach tcfe, an increase of 40-50% from 2009 levels Risked unproved resources should reach tcfe, an increase of % from 2009 levels Debt should be reduced below $10 billion and fully diluted common shares outstanding should remain around 675 million Risk disclosure regarding unproved resource estimates appears on page 30 (1) Based on 10-Year average NYMEX strip pricing pro forma for Barnett JV 4

5 CHK s 3 Year Growth Projection Last 3 years Next 3 Years % Change 2012E Next 3 Years % Change Production (bcfe/d) (1) 56% % - 50% Adjusted Ebitda ($bln) $4.4 $4.4 (2) -1% $5.2 - $7.0 20% - 60% Proved Reserves (tcfe) % % - 45% Risked Unproved Resources (tcfe) (2) 269% % - 100% Total Resource Base (bcfe) % % - 90% Long Term Debt ($billion) $7.4 $ % $10.0 ~ -20% Debt per Proved Mcfe $0.83 $0.79-4% $ $0.50 ~ -45% Debt per Total Resource Base Mcfe $0.28 $ % $0.07 ~ -55% Ending FD Common Shares Outstanding (mm) % 675 2% Proved Reserves/FD es/ Share (mcfe/share) e) % % - 55% Total Resource/FD Share (mcfe/share) % % - 85% Share Price $29.05 $ %?? Market Cap ($billion) $15.1 $ %?? Enterprise Value $23.2 $ %?? Average Daily NYMEX Gas Price $7.13 $ %?? CHK s value creation process is a low-risk manufacturing operation that should deliver industry-leading asset value growth to shareholders Risk disclosure regarding unproved resource estimates appears on page 30 (1) Reconciliations of non-gaap financial measures to comparable GAAP measures appear on page 29 (2) Based on 10-Year average NYMEX strip pricing; 14.3 tcfe at 12/31/09 using SEC pricing 5

6 Powerful Assets Create Powerful Value

7 CHK s Operating Areas CHK is transitioning away from 92% natural gas to a greater balance between natural gas and oil 7

8 America s #1 Gas Resource Base CHK is exceptionally well positioned for longterm profitable growth Largest combined inventories of leasehold and 3-D seismic data in the industry 2.4 bcfe of current daily production, 93% gas 14.6 tcfe of proved reserves (1)(2), 95% gas 65 tcfe of risked unproved resources (1)(2) 177 tcfe of unrisked unproved resources (1)(2) 13.7 million net acres of leasehold (1) Net Acreage 13.7 million acres 2.9 Drillsites ~35,750 net drillsites ,450 Proved Undeveloped Reserves 16,300 Risked Unproved Resources 23.6 million acres of 3D seismic data >10-year inventory of ~36,000 net drillsites (1) 6.3 tcfe 64.5 tcfe All other Big 6 shale plays (3) Risk disclosure regarding unproved resource estimates appears on page 30 1) Pro forma for January 2010 Barnett Shale joint venture transaction 2) Based on 10-Year average NYMEX strip pricing pro forma for Barnett JV; 14.3 tcfe at 12/31/09 using SEC pricing before Barnett JV 3) The Big 6 consists of the Marcellus, Haynesville, Barnett, Fayetteville, Bossier and Eagle Ford shale plays 8

9 CHK s Drilling Inventory (1) Total Proved Reserves Est. Risked Est. Avg. Total Risked and Risked Unrisked Current Feb-09 CHK CHK Drilling Net Reserves Proved Unproved Unproved Unproved Daily Operated Industry Net Density Risk Undrilled Per Well Reserves Resources Resources Resources Production Rig Play Area Position Acreage (1) (Acres) Factor Royalty Wells (1) (bcfe) (bcfe) (1)(2) (bcfe) (2) (bcfe) (1)(2) (bcfe) (1)(2) (mmcfe) (1)(3) Count Big 6 Shale Plays: Marcellus Shale #1 1,570, % 15% 5, ,900 21,165 69, Haynesville Shale #1 535, % 25% 3, ,960 17,400 19,360 30, Fayetteville Shale #2 455, % 17% 4, ,225 6,900 9,125 9, Barnett Shale #2 220, % 25% 1, ,756 2,800 5,556 3, Bossier Shale #1 180, % 25% ,900 1,900 9,300 ND (6) 0 Eagle Ford Shale (4) Top 10 80, % 25% ,600 ND (6) 1 Big 6 Shale Play Subtotals (5) 2,860,000 Various 16,300 Various 7,206 50,100 57, ,700 1, Colony Wash #1 120, % 20% ,900 2,343 2, Texas Panhandle Granite Wash #1 70, % 20% ,200 1,870 1, Other Top 3 10,650,000 Various 18,550 Various 6,303 11,300 17,603 48, Total 13,700,000 35,750 14,622 64,500 79, ,700 2, Advances in horizontal drilling completion technologies have driven a fundamental shift towards shale and unconventional resources in the past four years CHK s portfolio contains the best assets in the most prolific resource plays within the U.S., which will enable it to excel in providing cleanburning natural gas for many years to come Risk disclosure regarding unproved resource estimates appears on page 30 1) Pro forma for January 2010 Barnett Shale joint venture transaction 2) Based on 10-Year average NYMEX strip pricing; 14.3 tcfe at 12/31/09 using SEC pricing before Barnett JV 3) Estimated February 2010 average 4) As of April 8, 2010 CHK s Eagle Ford Shale acreage approximates 300,000 net acres 5) Bossier Shale acreage overlaps with Haynesville Shale acreage and is excluded from the Big 6 acreage subtotal to avoid double counting of acreage 6) Not disclosed 9

10 Big Oil on the Way to CHK Gross Unrisked Unrisked Horizontal Net Unproved Unproved CHK Wells Unrisked Resources Resources Net Drilled Undrilled Per Well to CHK Horizontal Play Area State Acreage To Date Wells (MBOE) NRI (MMBOE) 1. S. Texas Eagle Ford Shale TX 300, , % 1, Colony Granite Wash OK 120, , % TX PH Granite Wash TX 70, % Anadarko Basin Cleveland OK 100, % Anadarko Basin Tonkawa OK 100, % Anadarko Basin Mississippiani i i OK 200, , % Permian Avalon Shale TX,NM 120, % Permian Bone Spring TX 70, % PRB Niobrara WY 250, , % PRB Frontier WY 50, % 115 Totals 1,380, ,710 4,355 CHK owns ~4.35 billion barrels of oil equivalent upside on leasehold it already owns in plays where it already has proven the play concept works 10

11 Marcellus Shale Overview ~4 460 miles Prospective Area = ~15 Million Acres White 2H Peak Rate: 8.7 mmcfe/d White 5H Peak Rate: 8.6 mmcfe/d Benscoter 3H Peak Rate: 8.4 mmcfe/d CHK Acreage CHK Operated Rigs The Marcellus Shale play is likely to become one of the two largest gas fields in the U.S. (Haynesville the other) CHK is the second largest producer, the most active driller and the largest leasehold owner in the play with 1.6 mm net acres of leasehold 67.5/32.5 JV with Statoil (STO) in 11/08; $3.375 billion in cash and drilling carries Currently operating 24 rigs in the play; plan to average ~32 rigs in 10 to drill ~175 net wells Anticipate net production reaching ~270 mmcfe/d by year-end 10 and 450 mmcfe/d by year-end 11 After Statoil sale, CHK s leasehold investment in the Marcellus is only ~$330/net acre on average, by far the lowest in the industry ~400 miles Risk disclosure regarding unproved resource estimates appears on page 30 11

12 Haynesville Shale Overview ~110 miles Sloan H-1 Peak Rate: 23.4 mmcf/d Prospective Area = ~3.0 Million Acres Caspiana H-1 Peak Rate: 20.2 mmcf/d Chesapeake Operated Rigs CHK Non-op Rigs CHK Acreage Johnson H-1 Peak Rate: 18.5 mmcf/d ~95 miles CHK discovered in 2007; the Haynesville Shale is likely to become one of the two largest natural gas fields in the U.S. (Marcellus the other) CHK is the largest leasehold owner in the play with ~535,000 net acres, primarily focused in the core 80/20 JV with PXP in 7/08; received $3.1 billion in cash and drilling carries for 20% sale CHK received ~$1.1 billion in cash from PXP on 9/29 Currently operating 38 rigs in the play; plan to average ~41 rigs in 10 to drill ~200 net wells Anticipate reaching ~640 mmcfe/d by year-end end 2010 and ~810 mmcfe/d by year-end 2011 CHK s leasehold investment in the Haynesville has been ~$5.3 billion, of which ~$2.8 billion, or 52%, has been recouped by the JV with PXP CHK s net investment in Haynesville leasehold is now ~$4,600/net acre on average Risk disclosure regarding unproved resource estimates appears on page 30 12

13 CHK #1 in the Haynesville/Bossier Core TEXAS CHK Acreage CHK HBP LOUISIANA Haynesville Shale Outline Bossier Shale Outline CHK discovered the Haynesville and from the beginning targeted the Core In the past three years, CHK has built the dominant leasehold position in the Core CHK has already HBP d ~155,000 net acres (~30%) of total 535,000 net acres Estimated HBP by YE 10 ~220,000 net acres (from CHK operated wells only) Estimated HBP by YE 11 ~330,000 net acres (from CHK operated wells only) Estimated HBP by YE 12 ~430,000 net acres (from CHK operated wells only) CHK intends to sell ~80,000 net acres of non-core leasehold in 2010 CHK has only booked 10% of its proved and risked unproved resources CHK owns a leasehold interest in ~1, acre sections and controls operations in ~600 of these sections 13

14 Bossier Shale Overview ~110 miles Bossier Shale Prospective Area = ~1.0 Million Acres Blackstone 26 H-1 IP: 9.4 mmcfe/d CHK is the largest leasehold owner in the play CHK currently owns ~180,000 net acres of leasehold prospective e for Bossier Shale CHK s leasehold position in the Bossier Shale has risked unproved resources of ~1.9 tcfe and unrisked unproved resources of ~9.3 tcfe (1) Currently completing second Bossier Shale well, Muench 10H-1, in southern DeSoto Parish ~10 additional industry Bossier Shale horizontal wells are currently producing First 2 CHK wells successful No ramp up in drilling until acreage HBP, possibly starts in Haynesville Shale Trend Bossier Shale Trend ~95 miles Chesapeake Operated Rigs CHK Non-op Rigs CHK Acreage 1) As of 12/31/09. Assumes EUR of 5.5 bcfe/well and 80% risk factor Risk disclosure regarding unproved resource estimates appears on page 30 CHK has the industry s largest combined resource potential in the Haynesville and Bossier Shales 14

15 Fayetteville Shale Overview ~4 40 miles Gardner H Peak Rate: 6.2 mmcfe/d Prospective Area = ~1.7 Million Acres Stroud H14 Peak Rate: 7.9 mmcfe/d Chesapeake Operated Rigs ~115 miles CHK Non-op Rigs Nicholson H9 Peak Rate: 9.2 mmcfe/d CHK Acreage CHK is the second-largest producer in the Fayetteville Shale and the second-largest leasehold owner in the Core area of the play 75/25 JV with BP in 9/08; $1.9 billion in cash and drilling carries (drilling carries were 100% collected by YE 2009) Anticipate maintaining ~320 mmcfe/d through year-end 11 Currently operating 12 rigs to further develop ~455,000 net acres of leasehold; plan to average ~10 rigs to drill net wells in 2010 CHK s leasehold investment in the Fayetteville has been ~$530 million and by selling 25% to BP for ~$880 million, CHK has more than recouped its entire leasehold investment no other company has lower cost leasehold in the play than CHK 15

16 Barnett Shale Overview ~82 miles Core & Tier 1 Outline Crowley Eagles 1H Peak Rate: 9.6 mmcfe/d Prospective Area = ~1.5 Million Acres Crowley Eagles 4H Peak Rate: 10.4 mmcfe/d Auld 1H Peak Rate: 13.0 mmcfe/d Chesapeake Operated Rigs CHK Non-op Rigs CHK Acreage The Barnett Shale is currently the largest natural gas producing field in the U.S. and is producing ~50% of all shale gas in the U.S. CHK is the largest leasehold owner, most active driller and largest producer in the Core and Tier 1 sweet spot of Tarrant and Johnson Counties Anticipate reaching ~590 mmcfe/d by year-end end 10 and ~665 mmcfe/d by year-end 11 75/25 JV with TOT in 1Q 10; $2.25 billion in cash ($800mm) and drilling carries ($1.45 billion) TOT will acquire its 25% share of the new acreage on promoted terms until December 31, 2015 CHK anticipates drilling gross wells per year for years to come in the Barnett ~67 miles 16

17 Greater Granite Wash Overview OK CHK Op Rigs TX ~70miles Reed T8H Peak Rate: 10.6 mmcfe/d Ruby Lee 102H Peak Rate: 17.8 mmcfe/d Ruby Lee 103H Peak Rate: 12.8 mmcfe/d Texas Panhandle Granite Wash Colony Granite Wash CHK Non-Op Rigs Industry Rigs CHK Acreage Shirl Ann 1-14H Peak Rate: 21.8 mmcfe/d Lee Roy 1-24H Peak Rate: 21.6 mmcfe/d Javorsky 1-33H Peak Rate: 20.6 mmcfe/d ~160 miles Texas Panhandle Granite Wash Greater Colony Granite Wash Located in Hemphill, Wheeler, Roberts counties, Located in Custer and Washita counties, OK TX and far western Roger Mills, OK CHK is the largest leasehold owner with ~120,000 CHK is one of the largest leasehold owners in net acres and is the most active driller the play with ~70,000 net acres Producing ~110 mmcfe/d at 12/31/09 Producing ~90 mmcfe/d at 12/31/09 CHK is the largest leasehold owner in the Greater Granite Wash Play with ~190,000 net acres 17

18 Financial Overview

19 2010 Financial Projections at Various Natural Gas Prices As of 2/17/10 Outlook ($ in millions; oil at $80.00 NYMEX) $5.00 $6.00 $7.00 $8.00 $9.00 O/G revenue 985 bcfe (1) $4,720 $5,290 $5,910 $6,500 $7,090 Hedging effect (2) 1,650 1, Marketing and other (@ $0.13/mcfe) Production taxes 5% (240) (260) (300) (320) (350) LOE (@ $0.90/mcfe) (890) (890) (890) (890) (890) G&A (@ $0.43/mcfe) (3) (420) (420) (420) (420) (420) Ebitda 4,950 5,140 5,290 5,450 5,570 Interest (@ $0.33/mcfe) (320) (320) (320) (320) (320) Operating cash flow (2)(3)(4) 4,630 4,820 4,970 5,130 5,250 Oil and gas depreciation (@ $1.45/mcfe) (1,430) (1,430) (1,430) (1,430) (1,430) Depreciation of other assets (@ $0.23/mcfe) (220) (220) (220) (220) (220) Income taxes (38.5% rate) (1,150) 150) (1,220) (1,280) (1,340) (1,390) Net income to common (1) $1,830 $1,950 $2,040 $2,140 $2,210 Net income to common per fully diluted shares $2.85 $3.04 $3.18 $3.33 $3.44 Net debt/ebitda (5) Debt to book capitalization ratio 44% 44% 43% 43% 43% Ebitda/fixed charges (including pfd. Dividends) (6) MEV/operating cash flow (7) 3.6x 3.4x 3.3x 3.2x 3.1x EV/ebitda (8) 6.0x 5.8x 5.6x 5.5x 5.3x PE ratio (9) 8.8x 8.2x 7.9x 7.5x 7.3x CHK basically immune to further changes in 2010 (1) Before effects of unrealized hedging gain or loss (2) Includes the non-cash effect of lifted hedges (3) Includes charges related to stock based compensation natural gas and oil prices (4) Before changes in assets and liabilities (5) Net Debt = long-term debt less cash (6) Fixed charges ($716 mm) = interest expense of $694 million plus deferred dividends of $22 million (7) MEV (Market Equity Value) = $16.5 billion ($25.00/share x 660mm fully diluted shares as of 12/31/09) (8) EV (Enterprise Value) = $29.7 billion (Market Equity Value, plus $12 billion in net long-term debt plus $1.2 billion working capital deficit) (9) Assuming a common stock price of $25.00/share 19

20 2011 Financial Projections at Various Natural Gas Prices As of 2/17/10 Outlook ($ in millions; oil at $80.00 NYMEX) $5.00 $6.00 $7.00 $8.00 $9.00 O/G revenue 1,140 bcfe (1) $5,370 $6,190 $7,020 $7,850 $8,680 Hedging effect (2) Marketing and other (@ $0.13/mcfe) Production taxes 5% (270) (310) (350) (390) (430) LOE (@ $0.90/mcfe) (1,030) (1,030) (1,030) (1,030) (1,030) G&A (@ $0.43/mcfe) (3) (480) (480) (480) (480) (480) Ebitda 4,110 4,890 5,680 6,400 7,130 Interest (@ $0.33/mcfe) (370) (370) (370) (370) (370) Operating cash flow (2)(3)(4) 3,740 4,520 5,310 6,030 6,760 Oil and gas depreciation (@ $1.45/mcfe) (1,650) (1,650) (1,650) (1,650) (1,650) Depreciation of other assets (@ $0.23/mcfe) (260) (260) (260) (260) (260) Income taxes (38.5% rate) (700) (1,000) (1,310) (1,590) (1,870) Net income to common (1) $1,130 $1,610 $2,090 $2,530 $2,980 Net income to common per fully diluted shares $1.75 $2.49 $3.23 $3.91 $4.60 Net debt/ebitda (5) Debt to book capitalization ratio 38% 37% 36% 36% 35% Ebitda/fixed charges (including pfd. Dividends) (6) MEV/operating cash flow (7) 4.4x 3.7x 3.1x 2.7x 2.4x EV/ebitda (8) 7.2x 6.1x 5.2x 4.6x 4.2x PE ratio (9) 14.3x 10.0x 7.7x 6.4x 5.4x CHK lightly hedged in 2011, biding our time, waiting for low prices to cure low prices (1) Before effects of unrealized hedging gain or loss (2) Includes the non-cash effect of lifted hedges (3) Includes charges related to stock based compensation (4) Before changes in assets and liabilities (5) Net Debt = long-term debt less cash (6) Fixed charges ($716 mm) = interest expense of $694 million plus deferred dividends of $22 million (7) MEV (Market Equity Value) = $16.5 billion ($25.00/share x 660mm fully diluted shares as of 12/31/09) (8) EV (Enterprise Value) = $29.7 billion (Market Equity Value, plus $12 billion in net long-term debt plus $1.2 billion working capital deficit) (9) Assuming a common stock price of $25.00/share 20

21 Cash Resource Plan (1) 2010E 2011E Total Operating Cash Flow (1)(2) $4,900-5,000 $5,300-6,000 $10,200-11,000 Net leasehold and producing properties transactions $1,300-1,700 $1,000-1,300 $2,300-3,000 Drilling capital expenditures ($4,100) - (4,400) ($4,300) - (4,600) ($8,400) - (9,000) Dividends, capitalized interest, cash income taxes, etc. ($350) - (400) ($500) - (600) ($850) - (1,000) Other ($500) - (600) ($250) - (300) ($750) - (900) Projected Net Cash Change $1,250 - $1,300 $1,250 - $1,800 $2,500 - $3,100 Production (bcfe per day) Proved reserves (3) (tcfe) Proved reserves per fully diluted d share (mcfe) YOY % change in proved reserves per FD share % 13% Long-term debt, net of cash on hand ($ in millions) $10,800 $9,300 Long-term debt per mcfe of proved reserves $0.68 $0.52 (1) From Outlook issued 2/17/10 and assumes NYMEX prices of $6.50-$7.50/mcf, $80/bbl; and $7.00-$8.00/mcf, $80/bbl in 2010 and 2011, respectively (2) Before changes in assets and liabilities (3) Under SEC proved reserve definitions as of 12/31/09 21

22 CHK s Natural Gas and Oil Hedge Positions for (1)(2) Natural Gas Swaps (3) Volume Hedged (bcf) % Hedged NYMEX Volume Hedged Avg. Price Natural Gas Collars (4) (bcf) % Hedged NYMEX Avg. Floor Price Nymex Avg. Ceiling Price Q 110 $7.53 1Q 43 $6.49 $8.51 2Q 123 $7.43 2Q 16 $7.04 $9.17 3Q 118 $7.60 3Q 4 $7.60 $ Q 119 $7.75 4Q 4 $7.60 $ Total % $ Total 67 8% $6.75 $ Total 72 7% $ Total 7 1% $7.70 $11.50 Oil (5) Volume Hedged (mmbbls) % Hedged NYMEX Avg. Price Q 2.2 $ Q 2.3 $ Q 2.3 $ Q 2.3 $ Total % $ Total % $96.09 NYMEX Strip 3/8/2010 Oil Natural Gas 2010 $81.81 $ $85.94 $ $87.35 $ $88.42 $ $89.58 $ Year Average ( ) $86.62 $ realized hedging gains: ~$4.4 billion (1) Excludes written calls (2) Assumes approximately the midpoint of company production forecast for each item and includes hedging positions as of 2/17/10 (3) Includes positions with knockout provisions for 2% of 2010 natural gas production at knockout prices of $ $6.75/mcf and 2% of 2011 natural gas production at knockout prices of $ $6.50 (4) Includes three-way collars (5) Includes knockout swaps 22

23 CHK Hedging: A Value Added Skill 800 Quarterly Realized Gains and Losses 1Q'01-4Q' CHK s hedging program has generated ~$4.4 billion in realized cash gains 400 since inception in 2001 $ in millions (200) (400) (600) We don t hedge just to say we re hedged. We hedge to make money, successfully done so 14 of past 16 quarters. That s not luck, that s skill! 23

24 Summary

25 What Are Unproved Resources and Unproved Acreage Worth Today? Unrisked Risked Time Unrisked Unrisked Risked Risked Time Adjusted Estimated Unproved Acreage Value Unproved Acreage Value Unproved Acreage Value Unproved Acreage Value Adjusted Estimated Risked Unproved Risked Unproved Total Net Unproved $7.00 $7.00 Gas $ 7.00 $7.00 Gas Value/Acre Resources Resources Play Areas Acreage (1) Net $7.00 Gas ($ in mm) ($ in bln) Factor ($ in mm) ($ in $7.00 Gas (tcfe) ($/mcfe) Marcellus Shale (2) 1,570,000 1,563,100 $35,900 $56,115 $ % $16,835 $16.8 $10, $0.81 Haynesville Shale (2) 535, ,500 $38,100 $18,879 $ % $11,327 $11.3 $22, $0.65 Fayetteville Shale (3) 455, ,400 $16,000 $5,798 $5.8 20% $4,639 $4.6 $12, $0.67 Barnett Shale (3) 220, ,800 $18,000 $2,264 $2.3 15% $1,925 $1.9 $15, $0.69 Bossier Shale (2)(4) 180, ,000 $26,800 $4,824 $4.8 80% $965 $1.0 $5, $0.51 Eagle Ford Shale Eagle Ford Shale (2) (5) 80,000 80,000 $11,100 $888 $0.9 90% $89 $0.1 $1, $0.44 Greater Colony Wash (3) 120,000 96,500 $53,000 $5,115 $5.1 25% $3,836 $3.8 $39, $2.02 TX Panhandle Wash (3) 70,000 37,100 $38,000 $1,410 $1.4 25% $1,057 $1.1 $28, $0.88 Other 10,650,000 8,147,700 $2,000 $16,295 $ % $4,074 $4.1 $ $0.36 $7.00 Gas 13,700,000 11,088,100 $10, ,588 $ % $44,746 $44.7 $4, $0.69 Total $5.00 Gas $4,100/acre $17.7 $1,600/acre $0.27 $6.00 Gas $7,100/acre $31.2 $2,900/acre $0.48 $8.00 Gas $13,300/acre $58.3 $5,300/acre $0.90 $9.00 Gas $16,300/acre $71.8 $6,600/acre $1.11 (1) As of 12/31/09, pro forma for Barnett JV (2) Based on 10 year PV10 economic development assumption (3) Based on a 5-year PV10 economic development assumption (4) Not included in total due to overlap in Haynesville Shale acreage (5) As of 4/8/10, CHK s Eagle Ford acreage is ~300,000 net acres 25

26 CHK = Exceptional Value Pro forma (1) 12/31/2009 various NYMEX gas prices (2) Average NYMEX Natural Gas Prices ($ in millions, except per share data) $5.00 $6.00 $7.00 $8.00 $9.00 Proved developed reserves - PV10 $ 11,400 $ 14,500 $ 17,600 $ 20,700 $ 23,900 Proved undeveloped reserves - PV10 3,600 5,900 8,300 10,800 13,200 Unproved resoures (3) 17,700 31,100 44,700 58,200 71,700 Value of CHK hedges (4) 2,000 1,600 1, (600) Other assets (5) , ,500 5, , ,500 STO and TOT: PV10 of future drilling cost receivables 2,900 2,900 2,900 2,900 2,900 Less: long-term debt (net of cash equivalents) (12,000) (12,000) (12,000) (12,000) (12,000) Less: preferred stock (when not dilutive) (500) (300) Less net working capital (1,200) (1,200) (1,200) (1,200) (1,200) Shareholder value $ 29,400 $ 48,000 $ 67,000 $ 85,500 $ 103,400 Fully diluted common shares (in millions) (6) NAV per share $ $ $ $ $ Potential % upside (6) 81% 194% 306% 418% 527% Asset value to long-term debt 35x 3.5x 50x 5.0x 66x 6.6x 81x 8.1x 96x 9.6x NYMEX Strip 3/8/2010 Oil Natural Gas 2010 $81.81 $ $85.94 $ $87.35 $ $88.42 $ $89.58 $6.36 (1) Pro forma for Barnett JV with Total (2) NYMEX gas price changes and NYMEX oil price held constant at $61.14 per bbl 5-Year Average ( ) (3) 64.5 tcfe of unproved resources, see page 7 for valuation approach $86.62 $5.84 (4) Per Outlook issued on 2/17/10 (5) Buildings, drilling rigs, midstream gas assets (excluding JV assets) at net book value and investments at market value (6) Based on common stock price of $25.00 per share 26

27 CHK: Positioned for Success in 2010 and Beyond Great Assets #1 combined leasehold position in the Big 6 shale plays 14.6 tcfe of proved resources at 12/09 (20-22 tcfe by 2012), ~65 tcfe risked unproved resources (1) Great Returns Finding costs should average <$1.50 per mcfe for years to come Low overhead and production costs, combined with low finding costs, should provide CHK with the highest returns in the industry for years to come Innovative Joint Ventures World-class partners (BP, PXP, STO and TOT) with $3.4 billion of future JV carry receivables Sold $2.7 billion of assets for $10.7 billion, retained remaining JV assets worth ~$33 billion Attractive Valuation Trade at a substantial discount to estimated NAV and to XOM-XTO multiples and way below single shale growth companies Well Structured Balance Sheet Staggered long-term maturity structure with no senior notes due until 2013 Still Growing Strong Projecting growth of ~8-10% in 2010 and ~15-17% in 2011, respectively, and after asset sales Looking for and finding more oil! Data above incorporates: CHK s press release and Outlook dated 2/17/10 Risk disclosures regarding unproved resource estimates on page 30 (1) Based on 10-Year average NYMEX strip pricing pro forma for Barnett JV; 14.3 tcfe at 12/31/09 using SEC pricing before Barnett JV 27

28 Corporate Information Chesapeake Headquarters 6100 N. Western Avenue Oklahoma City, OK Web site: Common Stock NYSE: CHK Other Publicly Traded Securities CUSIP Ticker 7.5% Senior Notes due 2013 #165167BC0 CHK % Senior Notes due 2013 #165167BY2 CHKJ13 7.5% Senior Notes due 2014 #165167BG1 CHK14 7.0% Senior Notes due 2014 #165167BJ5 CHKA % Senior Notes due 2015 #165167BL0 CHKJ15 9.5% Senior Notes due 2015 #165167CD7 CHK15K Contacts: Jeffrey L. Mobley, CFA Senior Vice President Investor Relations and Research (405) John J. Kilgallon Manager Investor Relations and Research (405) % 625% Senior Notes due 2016 #165167BN6 CHKJ16 com 6.875% Senior Notes due 2016 #165167BE6 CHK % Senior Notes due 2017 #165167BS5 CHK % Senior Notes due 2017 # N/A 6.25% Senior Notes due 2018 #165167BQ9 CHK % Senior Notes due 2018 #165167CC9 CHK18A Marcus C. Rowland Executive Vice President and 6.875% Senior Notes due 2020 #165167BU0 CHK20 Chief Financial Officer 2.75% Contingent t Convertible Senior Notes due 2035 #165167BW6 CHK35 (405) marc.rowland@chk.com 2.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/165167CA3 CHK37/CHK37A 2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38 5.0% Cumulative Convertible Preferred Stock (Series 2005) # N/A 4.5% Cumulative Convertible Preferred Stock # CHK PrD 5.0% Cumulative Convertible Preferred Stock (Series 2005B) # N/A 28

29 Reconciliation of Adjusted EBITDA ($ in millions) (unaudited) (a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options. (b) Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-gaap financial measures as a useful adjunct to ebitda because: i. Management uses adjusted ebitda to evaluate the company s operational trends and performance relative to other natural gas and oil producing companies. ii. Adjusted ebitda is more comparable to estimates provided by securities analysts. iii. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. 29

30 Certain Reserve & Production Information The Securities and Exchange Commission requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. In this presentation, we use the terms "risked and unrisked unproved resources" and "estimated average resources per well" to describe Chesapeake's internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. These may be broader descriptions of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. We believe our estimates of unproved resources, both risked and unrisked, are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the forecasts are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions and data or by known or unknown risks and uncertainties. 30

31 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. They include estimates of our natural gas and oil reserves and resources, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned asset sales, budgeted capital expenditures for drilling and acquisitions of leasehold and producing property, 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. Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Although we believe the expectations and forecasts reflected in forward-looking statements 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. Factors that could cause actual results to differ materially from expected results are described under Risk Factors in our 2009 Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; impacts the current economic downturn may have on our business and financial condition; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including through planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; exploration and development drilling that does not result in commercially productive reserves; expiration of natural gas and oil leases that are not held by production; hedging activities resulting in lower prices realized on natural gas and oil sales and the need to secure hedging liabilities; uncertainties in evaluating natural gas and oil reserves of acquired properties and potential liabilities; the negative impact lower natural gas and oil prices could have on our ability to borrow; drilling and operating risks, including gp potential environmental liabilities; transportation capacity constraints and interruptions that could adversely affect our cash flow; potential increased operating costs resulting from legislative and regulatory changes affecting our operations; and losses possible from pending or future litigation. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update this information. 31