November 2008 Investor Presentation

Transcription

1 November 2008 Investor Presentation ti

2 Introduction to CHK #1 producer of U.S. natural gas 3Q 08 natural gas production of 2,138 mmcf/day; ~3.5% of U.S. production; 2009E 2,475 mmcf/day and 2010E 2,880 mmcf/day #1 driller in U.S. ~136 operated rigs currently, on the way down to <130 until gas markets rebalance, ~100 nonoperated rigs, ~15 info only rigs; collector of ~15% of all daily drilling information generated in the U.S. (~20% in our areas of interest) #1 large-cap production growth Increased production by 23% in 07 to 2.0 bcfe/day; projecting increase of 17% in 08 to 2.3 bcfe/day and increases of 17% in 09 and 16% in 10 to 2.7 and 3.1 bcfe/day, respectively #1 large-cap proved reserve growth 12.1 tcfe estimated proved reserves at 9/30/08; targeting ~12.5 tcfe of proved reserves by 12/08 and tcfe by 12/09 #1 gas resource play 60 tcfe of risked unproved reserve potential; >10-year drilling inventory of 37,300 net drilling locations #1 inventory of U.S. onshore leasehold and 3-D seismic 15.6 mm net acres of U.S. onshore leasehold and 21.1 mm acres of 3-D seismic data Data above incorporates: Information as of 9/30/08 CHK s Outlook as of 11/3/08 Risk disclosure regarding unproved reserve estimates appears on page 33 2

3 Financial Highlights $29.1 billion enterprise value $14.9 billion equity value, $12.4 billion net long-term debt and $1.8 billion working capital deficit Strong profitability 2009E: ebitda $6.1 billion, operating cash flow $5.7 billion, net income to common $2.0 billion Well hedged 73% of 4Q 08, 67% of 2009 and 42% of 2010 production hedged at average prices of $9.09, $8.65 and $9.81 per mcfe, respectively Innovative joint venture arrangements CHK/PXP in Haynesville Shale: $3.3 billion for 20% interest CHK/BP in Fayetteville Shale: $1.9 billion for 25% interest CHK/STO in Marcellus Shale: $3.375 billion for 32.5% interest; close by year-end 2008 Prudent balance sheet Balanced financing mix of equity and long-term debt with long-dated fixed maturities Strong asset and cash flow coverage of debt Substantial asset growth, cash generation and earnings set to meaningfully deleverage CHK by YE 09 Anticipating substantial balance sheet improvement Strong asset growth and earnings growth expected over the next two years Since mid-september September, CHK reduced drilling capex by ~$3.7 billion, or ~20% and reduced leasehold and property expenditures by $1.4 billion or ~16% Expect to primarily direct $ billion of excess cash generation in 4Q 08 to debt reduction Great value to investors 2009E multiples: 2.6x operating cash flow, 4.8x ebitda, 7.3x P/E ratio Trading at steepest ever discount to estimated net asset value per share Data above incorporates: CHK s Outlook as of 11/3/08 Reconciliations to GAAP measures appear on page 22 Summary of hedging positions appear on page 25 An assumed common stock price of $25.00, NYMEX prices of $8.00/mcf and $80.00/bbl and excludes effects of FAS 133 (unrealized hedging gain or loss) 3

4 Strong 3Q 08 Results Top-tier production growth 3Q 08 production reaches 2.3 bcfe/day f/d 15% YOY average daily production increase; up 23% as adjusted for asset sales Strong 3Q 08 financial performance $1.4 billion of adjusted ebidta (1) ; up 16% YOY $1.4 billion of operating cash flow (1)(2) ) ; up 29% YOY $486 million of adjusted net income to common (1) ; up 47% YOY $0.85 of adjusted earnings per fully diluted common share (1) ; up 23% YOY Increased proved reserves at 9/30/08 to 12.1 tcfe YTD growth go of 11% or 1.2 tcfe tce During the first three quarters CHK replaced 630 bcfe of production with an estimated 1.8 tcfe of new proved reserves for a reserve replacement rate of 290% Achieved attractive drilling and net proved acquisition cost of $1.35/mcfe through the first three quarters of 2008 Risked unproved reserves increased to 60 tcfe; up 25% sequentially and 160% YOY Sales of undeveloped leasehold during the first three quarters of 2008 generated proceeds of $3.6 billion compared to a cost basis of ~$750 million for the leasehold sold 4 (1) Refer to the Investor Relations section of our website, under Non-GAAP Financial Reconciliations for reconciliation of this Non-GAAP measure to the comparable GAAP measure (2) Before changes in assets and liabilities

5 CHK/STO Marcellus Shale JV CHK has agreed to sell a 32.5% interest in its Marcellus Shale assets in Appalachia to StatoilHydro (NYSE: STO) for $ billion CHK will receive $1.25 billion in cash at closing and will receive a further $2.125 billion from 2009 to 2012 to fund 75% of CHK s 67.5% share of drilling and completion expenditures As a result of the transaction, STO will own ~0.6 mm net acres of this leasehold and CHK will own ~1.2 mm net acres CHK plans to continue acquiring leasehold in the Marcellus Shale play and STO will have the right to a 32.5% participation in additional leasehold CHK and STO have agreed to enter into an international strategic alliance to jointly explore unconventional natural gas opportunities worldwide Closing of the transaction is anticipated to occur by year-end end

6 CHK s Distinctive Business Strategy

7 We re Good at Anticipating Opportunities & Challenges CHK recognized earlier than most that higher oil and natural gas prices, combined with better drilling and completion technology, would potentially make unconventional gas resource plays highly economic Since 98, Chesapeake s business strategy has been to: Grow through an aggressive unconventional resource discovery and leasing program followed by large-scale drilling programs Recognize and mitigate risks throughout our business Maintain a balanced capital structure with long-term debt maturities Today, Chesapeake is well positioned for the future: Won the great early 21 st century land grab and built the nation s top gas resource base A top-3 position in every major U.S. onshore resource play east of the Rockies Developed world-class technical capabilities in unconventional resources and discovered multiple new plays Achieved substantial operating scale and vertical integration including the nation s 6th largest drilling rig fleet, related service businesses and a large midstream gathering and processing operation Built a successful and distinctive entrepreneurial corporate culture, thereby enabling CHK to have what it believes is the most talented, motivated and productive workforce in the industry Expanded employee base over 13-fold over the last ten years to 7,600 Now moving to advance present value forward through asset monetizations via VPP s and promoted partnerships 7

8 CHK s Business Model Chesapeake s large and diversified production base and leasehold inventory offers multiple monetization and value creation alternatives Volumetric production payments (VPPs) Leasehold joint ventures High-grading property sales Hedging gto secure strong gprofit margins Chesapeake s diversified, verticallyintegrated natural gas manufacturing machine is well positioned for future growth Industry-leading leasehold acquisition program 800 internal land department employees and 4,000 brokers 7,600 total employees, including 1,800 geoscience, engineering and operations department employees The nation s most active drilling program with 136 operated rigs, including 83 rigs in CHK s own rig fleet Large midstream gathering and processing operations Compression operations and manufacturing Apply Cutting-Edge Geoscience Technology to Discover New Plays Harvest Value by Selling Producing Properties and/or Proven Leasehold and through Everyday Production of Mcfe s Invest in High Quality Leasehold Drill Aggressively to Increase Production and Convert Leasehold to Proved Reserves 8

9 Asset Overview CHK drilling a Barnett Shale well near downtown Fort Worth, Texas

10 Location of CHK Properties Gas-focused Well-diversified All onshore U.S. Not in the GOM (high and dry) Not in the Rockies (fewer political/environmental hassles, better natural gas prices) Not international (lower political risk) Anadarko Basin Marcellus Shale Fayetteville Shale Counties with CHK leasehold Mississippian & Devonian black shales Barnett and Woodford Shale Plays Permian Basin Barnett Shale Haynesville Shale Thrust Belt Delaware Basin Ark-La-Tex CHK field offices CHK OKC headquarters CHK operated rigs (136) Scale: 1 inch = 275 miles CHK non-operated rigs (100) 10

11 America s #1 Gas Resource Base CHK is well positioned for long-term profitable growth Largest combined inventories of leasehold and 3-D seismic data in the industry 2.3 bcfe of daily production, 92% gas 12.1 tcfe of proved reserves, 93% gas 60.2 tcfe of risked unproved reserves 15.6 million net acres of leasehold 21.1 million acres of 3-D seismic data >10-year inventory of ~37,300 net drillsites Net Acreage 15.6 million acres Drillsites ~37,300 net drillsites 5,500 31, tcfe of unrisked unproved reserves Proved Undeveloped Risked Unproved Reserves Reserves 4.2 tcfe 60.2 tcfe Conventional gas resource Unconventional gas resource As of 9/30/08 Risk disclosure regarding unproved reserve estimates appears on page 33

12 CHK s Drilling Inventory Total Proved Est. Risked Est. Avg. Total Risked and Risked Unrisked Current CHK CHK Drilling Net Reserves Proved Unproved Unproved Unproved Daily Industry Net Density Undrilled Per Well Reserves Reserves Reserves Reserves Production Play Area Position (1) Acreage (Acres) Wells (bcfe) (bcfe) (bcfe) (bcfe) (bcfe) (mmcfe) Conventional Gas Resource Southern Oklahoma #1 345, ,640 3, South Texas #3 130, , Mountain Front #1 140, , Other Conventional Top 3 3,985,000 Various 4,450 Various 2,320 3,600 5,920 19, Conventional Sub-total 4,600,000 5,500 3,710 5,200 8,910 25, Unconventional Gas Resource Marcellus Shale #1 1,770, , ,200 17,245 68, Haynesville Shale #1 480, , ,400 14,600 29, Fort Worth Barnett Shale #2 315, , ,810 5,200 8,010 6, Fayetteville Shale (Core Area) #2 415, , ,600 7,135 8, Sahara #1 970, , ,125 2,800 3,925 4, Colony, Granite & Atoka Washes #1 333, , ,065 2,300 3,365 4, Deep Haley #1 500, ,200 1,470 6, Other Unconventional Top 3 6,217,000 Various 7,800 Various 2,310 5,300 7,610 36, Unconventional Sub-total 11,000,000 31,800 8,360 55,000 63, ,800 1,530 Total 15,600,000 37,300 12,070 60,200 72, ,400 2, As of 9/30/08 Risk disclosure regarding unproved reserve estimates appears on page 33

13 CHK was the Largest U.S. Natural Gas Producer in 3Q 08 Daily U.S. Natural Gas Production (a,b) Q'08 3Q'08 Reported U.S. Proved U.S U.S. Rigs vs. 2Q'08 vs. 3Q'07 Net Proved Gas Gas Reserve RP Drilling on Company (c) Ticker 3Q'08 2Q'08 3Q'07 % Change % Change Reserves Ranking Ratio (d) 11/7/08 (e) Chesapeake CHK 2,138 2,143 1,851 (0.2%) 15.5% 10, BP BP 2,094 2,140 2,186 (2.1%) (4.2%) 15, ConocoPhillips COP 2,073 2,132 2,335 (2.8%) (11.2%) 12, Devon DVN 2,006 1,939 1, % 12.4% 7, Anadarko APC 1,994 1,869 1, % 21.8% 8, XTO XTO 1,949 1,795 1, % 24.9% 9, EnCana ECA 1,674 1,629 1, % 20.7% 6, Chevron CVX 1,431 1,588 1,695 (9.9%) (15.6%) 3, EOG EOG 1,196 1, % 20.0% 4, ExxonMobil XOM 1,167 1,274 1,414 (8.4%) (17.5%) 13, Williams WMB , , (1.3%) 18.4% , Shell RDS 942 1,096 1,131 (14.1%) (16.7%) 2, El Paso EP (6.1%) (4.2%) 3, Apache APA (16.2%) (16.8%) 2, Occidental OXY (5.3%) (5.6%) 2, Southwestern SWN % 79.5% 1, Newfield NFX % (4.3%) 1, Questar STR % 38.5% 1, Marathon MRO (1.2%) (8.2%) 1, Noble NBL (4.5%) (5.0%) 1, Totals / Average 23,936 24,115 22, % 7.1% 112, (a) (b) (c) (d) (e) Based on company reports In mmcf/day Independents in blue, majors in black, pipelines in green Based on annualized 3Q 08 production Source: Smith International Survey (operated rig count) 13

14 What s New in the Haynesville Shale? 90 Miles CHK Horizontal Producing Wells Industry Horizontal Producing Wells Haynesville Penetrations CHK Acreage 100 Miles Area Within Outline = 3.5 Million Acres Horizontal Rigs Chesapeake Horizontal Rigs Industry CHK s largest discovery and expected to become the largest U.S. natural gas field Play encompasses a ~3.5 million acre area in NW Louisiana and E. TX CHK is the largest leasehold owner in the core area of the play, ~700,000 gross acres, ~480,000 net acres (after PXP 20 %), or ~20% of the play Planning to ramp from 14 rigs currently, up to ~35 by YE 09 Current net production of ~50 mmcfe/day (~65 mmcfe gross) Anticipate reaching ~80 mmcfe/day net by YE 08, ~325 mmcfe/day by YE 09 and ~615 mmcfe/day by YE 10 Based on drilling results by CHK, an EUR range of bcfe per well for the Core Area is reasonable with mid-point of 6.5 bcfe ~3,000 potential net risked wells in inventory to develop 14 tcfe of risked unproved reserves Currently have 130 bcfe of PUD reserves 14 Note: Risk disclosure regarding unproved reserve estimates appears on page 33

15 What s New in the Barnett Shale? 67 Miles Core & Tier 1 Outline 82 Miles CHK Acreage CHK Rigs CHK is the second-largest producer, most active driller and largest leasehold owner in the Core and Tier 1 sweet spots of Tarrant, Johnson and western Dallas counties Current net production of ~560 mmcfe/day is up ~37% YTD Anticipate reaching ~670 mmcfe/day net by YE 08, ~920 mmcfe/day net by YE 09 Have improved drilling efficiency and reduced avg. days to drill from days to days Planning to operate ~33 rigs in 2009 to further develop ~315,000 net acres of leasehold, of which ~280,000 net acres are located in the prime Core and Tier 1 areas Industry leading urban-drilling expertise has become a significant competitive advantage ~3,000 potential net risked wells in inventory to develop ~0.8 tcfe of PUD and 5.2 tcfe of risked unproved reserves 15 Note: Risk disclosure regarding unproved reserve estimates appears on page 33

16 What s New in the Fayetteville Shale? Fayetteville Penetrations CHK Acreage CHK Producing Wells Industry Producing Wells Chesapeake Rigs Industry Rigs CHK is the second-largest producer in the Fayetteville Shale and second-largest leasehold owner in the Core area of the play Planning to operate ~20 rigs in 2009 to further develop ~415,000 net acres of leasehold Current net production of ~145 mmcfe/day is up ~46% YTD Anticipate reaching ~165 mmcfe/day by YE 08, ~260 mmcfe/day by YE 09, ~300 mmcfe/day by YE 10 ~3,700 potential ti net risked wells in inventory to develop = ~6.8 tcfe of PUD and risked unproved reserves ~9 tcfe of PUD and unrisked unproved reserves Closed sale of 25% interest t in ~540, net acres and ~180 mmcfe/day of production to BP for $1.9 billion ($1.1 billion in cash, $800MM in carry) in September 2008 Secured firm transportation capacity of 375 mmcf/day and an option on 125 mmcf/day on the Fayetteville Express pipeline that will be built and operated by Kinder Morgan and Energy Transfer Late 2010/early 2011 completion 16 Note: Risk disclosure regarding unproved reserve estimates appears on page 33

17 What s New in the Marcellus Shale? CHK Acreage CHK Rigs CHK is a top-3 producer and the largest leasehold owner in the Marcellus Shale play Currently operating ~3 rigs to further develop ~1.8 million net acres of leasehold and plan to operate up to >15 rigs by YE 09 Current net production of ~15 mmcfe/day is up ~300% YTD Have agreed to sell a 32.5% interest in CHK s Marcellus Shale assets in Appalachia to StatoilHydro for $ billion CHK will receive $1.25 billion in cash at closing and will collect a further $2.125 billion from 2009 to 2012 to fund 75% of CHK s 67.5% share of drilling and completion expenditures 17 Note: Risk disclosure regarding unproved reserve estimates appears on page 33

18 Financial Overview

19 Strong Cash Margins and Steady Debt Levels per Mcfe $ / mcfe $9.50 $9.00 Net cash margin $8.50 Preferred dividends id d $8.00 $7.50 $7.00 $6.50 $6.00 $5.50 $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 (1) Interest expense (2) G&A Production tax Production expense Long term debt/mcfe of proved reserves Sr. Unsecured Q08 2Q08 3Q08 Rating B3/B B2/B B1/B+ B1/B+ Ba3/BB- Ba3/BB- Ba2/BB Ba2/BB Ba3/BB Ba3/BB 3Q 08 Averages (per mcfe) Realized price: $8.38 3Q 08 net cash margin: $6.18 Preferred dividends: $0.03 Interest expense: $0.26 G&A: $0.38 Production tax: $0.41 Production expense: $1.12 Total cash costs = $220 $ (1) Excludes unrealized gains/losses on interest rate derivatives (2) Excludes non-cash stock based compensation

20 Senior Note Maturity 9/30/08 / $4,000 $3,600 $3,200 $2,800 Total Senior Notes: $10.9 billion $3,595 (1) Average Rate: 5.4% Average Maturity: 8.3 years $2,780 (1) $2,400 $ in MM $2,000 $1,600 $1,200 $800 $400 Bank credit facility matures November 2012 $864 $600 $1,290 (1) $1,270 $500 $0 Rate: '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19 '20 7.5% 7.5% 2.75% 6.625% 2.5% 2.25% 6.875% 7.625% 7.0% 6.375% 6.875% 6.25% 7.25% 65% 6.5% 6.25% (1) Recognizes earliest investor put option as maturity 6.25% 20 Staggered long term debt maturity structure with no senior notes due for five years; cash flow of >$30 billion likely before first payment

21 2008 Financial Projections at Various Natural Gas Prices As of 11/3/08 Outlook ($ in millions; oil at $99.97 NYMEX) $6.00 $7.00 $8.00 $9.00 $10.00 O/G revenue 836 bcfe (1) $7,204 $7,315 $7,427 $7,538 $7,649 Hedging effect (2) (23) (66) (146) (216) (306) Marketing and other (@ $0.15/mcfe) Production taxes 5% (312) (317) (323) (329) (334) LOE (@ $1.08/mcfe) (903) (903) (903) (903) (903) G&A (@ $0.46/mcfe) (3) (385) (385) (385) (385) (385) Ebitda 5,706 5,769 5,795 5,830 5,846 Interest (@ $0.38/mcfe) (314) (314) (314) (314) (314) Operating cash flow (2)(3)(4) 5,392 5,455 5,481 5,516 5,532 Oil and gas depreciation (@ $2.35/mcfe) (1,965) (1,965) (1,965) (1,965) (1,965) Depreciation of other assets (@ $0.22/mcfe) (184) (184) (184) (184) (184) Income taxes (38.5% rate) (1,249) (1,273) (1,283) (1,297) (1,303) Net income to common (1) $1,994 $2,033 $2,049 $2,070 $2,080 Net income to common per fully diluted shares $3.55 $3.62 $3.65 $3.68 $3.70 Net debt/ ebitda (5) 2.2x 2.2x 2.1x 2.1x 2.1x Debt to book capitalization ratio 39% 39% 39% 39% 39% Ebitda/fixed charges (including pfd. dividends) (6) 9.1x 9.2x 9.3x 9.3x 9.3x MEV/operating cash flow (7) 2.8x 2.7x 2.7x 2.7x 2.7x EV/ebitda (8) 5.1x 5.0x 5.0x 5.0x 5.0x PE ratio (9) x x x x x (1) Before effects of FAS 133 (unrealized hedging gain or loss) (2) Includes the non-cash effect of CNR 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 ($626mm) = interest expense of $597 million plus dividends of $29 million (7) MEV (Market Equity Value) = $14.9 billion ($25.00/share x 596 mm fully diluted shares as of 09/30/08) (8) EV (Enterprise Value) = $29.1 billion (Market Equity Value, plus $12.4 billion of net long-term debt and $1.8 billion working capital deficit as of 9/30/08) (9) Assuming a common stock price of $25.00/share 21

22 2009 Financial Projections at Various Natural Gas Prices As of 11/3/08 Outlook ($ in millions; oil at $80.00 NYMEX) $6.00 $7.00 $8.00 $9.00 $10.00 O/G revenue 975 bcfe (1) $5,662 $6,456 $7,250 $8,044 $8,837 Hedging effect (2) , , (327) Marketing and other (@ $0.15/mcfe) Production taxes 5% (283) (323) (362) (402) (442) LOE (@ $1.15/mcfe) (1,121) (1,121) (1,121) (1,121) (1,121) G&A (@ $0.46/mcfe) (3) (449) (449) (449) (449) (449) Ebitda 5,058 5,750 6,101 6,432 6,644 Interest (@ $0.43/mcfe) (414) (414) (414) (414) (414) Operating cash flow (2)(3)(4) 4,644 5,336 5,687 6,018 6,230 Oil and gas depreciation (@ $2.25/mcfe) (2,194) (2,194) (2,194) (2,194) (2,194) Depreciation of other assets (@ $0.22/mcfe) (215) (215) (215) (215) (215) Income taxes (38.5% rate) (861) (1,127) (1,262) (1,390) (1,471) Net income to common (1) $1,374 $1,800 $2,016 $2,219 $2,350 Net income to common per fully diluted shares $2.34 $3.06 $3.43 $3.78 $4.00 Net debt/ebitda (5) Debt to book capitalization ratio 34% 34% 33% 33% 33% Ebitda/fixed charges (including pfd. dividends) (6) MEV/operating cash flow (7) 3.2x 2.8x 2.6x 2.5x 2.4x EV/ebitda (8) 5.8x 5.1x 4.8x 4.5x 4.4x PE ratio (9) 10.7x 8.2x 7.3x 6.6x 6.3x (1) Before effects of FAS 133 (unrealized hedging gain or loss) (2) Includes the non-cash effect of CNR 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 ($610mm) = interest expense of $586 million plus dividends of $24 million (7) MEV (Market Equity Value) = $14.9 billion ($25.00/share x 596 mm fully diluted shares as of 09/30/08) (8) EV (Enterprise Value) = $29.1 billion (Market Equity Value, plus $12.4 billion of net long-term debt and $1.8 billion working capital deficit as of 9/30/08) (9) Assuming a common stock price of $25.00/share 22

23 2010 Financial Projections at Various Natural Gas Prices As of 11/3/08 Outlook ($ in millions; oil at $80.00 NYMEX) $6.00 $7.00 $8.00 $9.00 $10.00 O/G revenue 1,130 bcfe (1) $6,524 $7,448 $8,372 $9,297 $10,221 Hedging effect (2) , Marketing and other (@ $0.15/mcfe) Production taxes 5% (336) (384) (431) (479) (526) LOE (@ $1.20/mcfe) (1,356) (1,356) (1,356) (1,356) (1,356) G&A (@ $0.46/mcfe) (3) (520) (520) (520) (520) (520) Ebitda 5,423 6,689 7,165 7,616 8,070 Interest (@ $0.38/mcfe) (424) (424) (424) (424) (424) Operating cash flow (2)(3)(4) 4,999 6,265 6,741 7,192 7,646 Oil and gas depreciation (@ $2.20/mcfe) (2,486) (2,486) (2,486) (2,486) (2,486) Depreciation of other assets (@ $0.22/mcfe) (249) (249) (249) (249) (249) Income taxes (38.5% rate) (872) (1,359) (1,542) (1,716) (1,891) Net income to common (1) $1,392 $2,171 $2,464 $2,741 $3,020 Net income to common per fully diluted shares $2.33 $3.63 $4.12 $4.59 $5.05 Net debt/ebitda (5) Debt to book capitalization ratio 28% 27% 27% 27% 27% Ebitda/fixed charges (including pfd. Dividends) (6) MEV/operating cash flow (7) 3.0x 2.4x 2.2x 2.1x 1.9x EV/ebitda (8) 5.4x 4.4x 4.1x 3.8x 3.6x PE ratio (9) 10.7x 6.9x 6.1x 5.4x 5.0x (1) Before effects of FAS 133 (unrealized hedging gain or loss) (2) Includes the non-cash effect of CNR 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 ($608mm) = interest expense of $586 million plus dividends of $22 million (7) MEV (Market Equity Value) = $14.9 billion ($25.00/share x 596 mm fully diluted shares as of 09/30/08) (8) EV (Enterprise Value) = $29.1 billion (Market Equity Value, plus $12.4 billion of net long-term debt and $1.8 billion working capital deficit as of 9/30/08) (9) Assuming a common stock price of $25.00/share 23

24 Cash Resource Plan 4Q (1) Net Cash Resources ($ in millions) Q4'08E 2009E 2010E Total Operating cash flow (1)(2) $1,250 - $1,375 $5,800 - $6,000 $6,250 - $6,750 $13,300 - $14,125 Leasehold and producing properties transactions Sales 2,100-2,500 1,250-2,000 1,250-2,000 4,600-6,500 Volumetric Production Payments ,000-1, , ,250 2,400-3,000 Acquisitions (750-1,000) (1,250-1,750) (1,000-1,500) (3,000-4,250) Net leasehold and producing properties transactions 1,750-2,000 1,000-1,500 1,250-1,750 4,000-5,250 Debt and equity offerings Midstream debt and equity financings 1,050-1, ,050-2,675 Proceeds from investments and other ,000 Total: $4,050 - $4,650 $7,800 - $8,950 $8,150 - $9,450 $20,000 - $23,050 Net Cash Uses ($ in millions) Drilling $1,200 - $1,300 $4,250 - $4,750 $4,750 - $5,250 $10,200 - $11,300 Geologic and geophysical Midstream infrastructure and compression ,000-1, ,000 2,200-2,525 Other PP&E Dividends, capitalized interest, etc ,300-1,400 Cash income taxes ,250 Total: $2,325 - $2,625 $6,500 - $7,425 $6,900 - $7,725 $15,725 - $17,775 Net Cash Change $1,725-2,025 $1,300-1,525 $1,250-1,725 $4,275-5,275 Revolving credit facility ($ in millions) Beginning balance, net of cash on hand $1,500 ($375) ($1,775) Potential change ($1,875) ($1,400) ($1,500) Ending balance, net of cash on hand ($375) ($1,775) ($3,275) Production (bcfe per day) Proved reserves (3) (tcfe) Proved reserves per fully diluted share (mcfe) YOY % change in proved reserves per FD share 16% 20% 13% Long-term debt, net of cash on hand ($ in millions) $10,925 $9,525 $8,025 Long-term debt per mcfe of proved reserves $0.87 $0.64 $ (1) From Outlook as of 11/3/08 and assumes NYMEX prices of $ $7.50/mcf and $60/bbl in 4Q 08 and $7.00-$8.00/mcf and $80/bbl in 2009 and 2010 (2) Before changes to asset and liabilities. Reconciliations to GAAP measures appear on pages (3) Under existing SEC proved reserve definitions likely to increase by up to 5 tcfe per year beginning 12/31/09

25 Successful Hedging Reduces Risk and Helps Secure Attractive Cash Margins CHK s natural gas and oil hedge positions for 4Q (1)(2) Natural Gas Swaps (3)(4) % Hedged NYMEX Avg. Price 4Q 2008 Total 62% $ Total 38% $ Total 40% $9.58 Natural Gas Collars (5) % Hedged NYMEX Avg. Floor Price Nymex Avg. Ceiling Price 4Q 2008 Total 14% $7.75 $ Total 30% $7.21 $ Total 2% $7.71 $11.46 Oil (6) % Hedged 4Q 2008 Total 43% 2009 Total 48% 2010 Total 37% NYMEX Avg. Price $78.09 $81.19 $90.25 NYMEX Strip 11/17/08 Oil Gas 4Q 2008 $ $ $ $ $ $ $ $ $ $ Year Average $ $ (1) Excludes written calls (2) Includes CNR derivative liabilities assumed at MTM value upon closing. Assumes approximately the midpoint of company production forecast for each item and includes hedging positions as of 11/3/2008 (3) Includes positions with knockout provisions for 5% of 4Q 08 production at knockout prices at $6.50/mcf and for 17% and 31%, respectively, for 2009 and 2010 production at knockout prices of $ $7.40/mcf (4) Does not include calls written with average premiums of $0.74 at average strike prices of $10.37 in 4Q 08, $0.63 and $11.40 in 2009 and $0.72 and $10.77 in 2010 (5) Includes three-way collars (6) Includes cap-swaps and knockout swaps 25

26 Summary

27 CHK = Great Value September 30, 2008 various NYMEX gas prices (1) Average NYMEX Natural Gas Prices ($ in millions, except per share data) $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 Proved reserves $ 15,600 $ 19,800 $ 23,900 $ 28,100 $ 32,300 $ 36,500 Unproved reserves (2) 6,000 12,000 24,100 36,100 48,100 60,200 Value of CHK hedges (3) 3,300 3,100 3,600 2,600 1, Value of CNR hedges - - (100) (100) (100) (200) Other assets (4) 4,500 4,500 4,500 4,500 4,500 4,500 PXP and BP future drilling cost receivables 2,400 2,400 2,400 2,400 2,400 2,400 Less: long-term debt (net of cash equivalents) (12,400) (12,400) (12,400) (12,400) (12,400) (12,400) Less: preferred stock (when not dilutive) (500) (300) Less net working capital (1,800) (1,800) (1,800) (1,800) (1,800) (1,800) Shareholder value $ 17,100 $ 27,300 $ 44,200 $ 59,400 $ 74,500 $ 89,500 Fully diluted common shares (in millions) (5) NAV per share $ $ $ $ $ $ Potential % upside (5) 17% 85% 197% 299% 400% 501% Asset value to long-term debt 2.4x 3.2x 4.6x 5.8x 7.0x 8.2x Leasehold Transaction Implied Values Undrilled Implied Shale Implied Shale NYMEX Strip 11/17/08 Acres Net Leasehold Leasehold Value Oil Gas Plays to CHK Value/Acre ($ in billions) 4Q 2008 $ $ 6.82 Marcellus Shale 1,800,000 $5,800 $ $ $ 7.02 Haynesville Shale 480,000 $15,000 $ $ $ 7.86 Fayetteville Shale 415,000 $12,500 $ $ $ 8.07 Fort Worth Barnett Shale Core & Tier 1 280,000 $17,500 $ $ $ 8.06 All other plays 12,625,000 $1,000 $12.6 Total 15,600, $2,587 $ Year Average $ $ (1) NYMEX natural gas price scenarios and NYMEX oil price held constant at $ per bbl (2) 60 tcfe of unproved reserves valued from $0.10-$1.00/mcfe (3) As of Outlook issued on 11/3/08 (4) Buildings, drilling rigs, midstream gas assets at net book value and investments at market value (5) Based on common stock price of $25.00 per share

28 Why Buy CHK? Gas Focus Purest play in U.S. natural gas; largest producer of U.S. natural gas Growth Total production growth of 23% in 07; projecting increases of 17% in 08 and 09 and 16% in 10 Sustainability 60 tcfe of proved and risked unproved reserves; >10-year drilling backlog of ~37,300 net drillsites across multiple gas resource plays Value Trade at a substantial discount to estimated NAV Diversified Risk Uniquely focused business strategy; well-diversified, all-onshore U.S. asset base Security Strong asset value to debt coverage; substantial cash flow generation capabilities Hedging Successful track record of locking in margins and investment returns during past five years Balance Sheet Balanced structure; long-term assets financed with long-term debt maturities; greatly expanded equity base Income Pay a $0.30 annual common stock dividend 28 Reflects CHK s Outlook as of 11/3/08 Risk disclosure regarding unproved reserve estimates appears on page 33

29 Appendix

30 Natural Gas Advantages CLEAN: Carbon-light structure represents a key advantage for America s energy future Natural gas is a simple molecule that contains only one carbon atom and four hydrogen atoms Natural gas is by far the cleanest-burning hydrocarbon on the planet Emits half the CO 2 of coal, contains low levels of nitrogen and sulfur dioxide and near zero levels of mercury or particulate emissions Drilling for natural gas leaves a small footprint Pad drilling, for example, is a great new innovation to further reduce surface impact AFFORDABLE: Natural gas prices are roughly 60% of the BTU equivalent price of oil Developing LNG market worldwide helps reduce gas price volatility in the U.S. In 2007, the cost of heating homes with natural gas per BTU was less than half that of electricity Compressed natural gas (CNG) is ~$2.00 per gallon cheaper than gasoline 30

31 Natural Gas Advantages ABUNDANT: Latest Colorado School of Mines Potential Gas Committee study estimate shows potential gas reserves of 1,525 tcf in the U.S. a 75-year supply! This new projection, coupled with Canadian projections, gives North America over 120 years of supply Recent shale discoveries change everything we know about natural gas supply in the U.S. and the world Higher natural gas prices combined with better drilling and completion technology has made a whole new class of assets economic to drill Thousands of acres have opened up for new drilling activity and future production growth AMERICAN: Natural gas is produced in 32 of 50 states benefits of greater production and use are very widespread 31

32 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 CHK13 7.5% Senior Notes Due 2014 #165167BG1 CHK14 Contacts: Jeffrey L. Mobley, CFA Senior Vice President Investor Relations and Research (405) Marcus C. Rowland 7.0% Senior Notes Due 2014 #165167BJ5 CHKA14 Executive Vice President and (405) % Senior Notes Due 2016 #165167BE6 CHK % Senior Notes Due 2015 #165167BL0 CHKJ % Senior Notes Due 2016 #165167BN6 CHKJ % Senior Notes Due 2017 #165167BS5 CHK % Senior Notes Due 2018 #165167BQ9 CHK % Senior Notes Due 2020 #165167BV0 CHK % Contingent t Convertible Senior Notes Due 2035 #165167BW6 CHK % Senior Notes Due 2013 #165167BY2 CHKJ % Senior Notes Due 2017 # N/A 2.50% Contingent Convertible Senior Notes Due 2037 #165167BZ9/165167CA3 CHK37/CHK37A 7.25% Senior Notes Due 2018 #165167CC9 CHK18A 2.25% Contingent Convertible Senior Notes Due 2038 #165167CB1 CHK38 32 (1) ISIN #

33 Certain Reserve & Production Information The Securities and Exchange Commission has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally yproducible under existing economic and operating conditions. We use the terms unproved reserves, including both risked and unrisked unproved reserves, reserve potential or upside, ultimate recovery and other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC s guidelines may prohibit us from including in filings with the SEC. To estimate unproved reserves, the company uses a probability-weighted statistical approach to estimate the potential number of drillsites and potential unproved reserves associated with such drillsites. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company. The company's methodology for estimating "unproved" reserves is different from the methodology and guidelines used by the Society of Petroleum Engineers for estimating "probable" and "possible" reserves. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Also, our internal estimates of reserves, particularly those in our recent acquisitions where we may have limited review of data or experience with the properties, may be subject to revision i and may be different from those estimates by our external reservoir engineers at year end. Although we believe the expectations, estimates and forecasts reflected in these and other forward-looking statements 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. 33

34 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 natural gas and oil reserves, expected natural gas and oil production and future expenses, projections of future natural gas and oil prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and planned asset sales, as well as statements concerning anticipated cash flow and liquidity, our 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 these and other 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 in Risk Factors in the Prospectus Supplement we filed with the Securities and Exchange Commission on July 10, These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent oil and gas companies and majors; the availability of capital on an economic basis, including gp 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; uncertainties in evaluating natural gas and oil reserves of acquired properties and associated potential liabilities; unsuccessful exploration and development drilling; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; lower prices realized on natural gas and oil sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower natural gas and oil prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; production interruptions that could adversely affect our cash flow; and pending or future litigation. We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures made in this presentation and our filings with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect our business. 34