October 2008 Investor Presentation

Transcription

1 October 2008 Investor Presentation

2 Introduction to CHK #1 producer of U.S. natural gas Natural outcome from the steady execution of our business model 2Q 08 natural gas production of 2,143 mmcf per day; ~3.5% of U.S. production #1 driller in U.S. 157 operated rigs, 91 non-operated 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 18% in 08 to 2.3 bcfe/day and increases of 16% in 09 and 10 to 2.7 and 3.1 bcfe/day, respectively #1 large-cap proved reserve growth 11.8 tcfe estimated proved reserves at 6/30/08 (pro forma for asset sales); targeting ~13 tcfe of proved reserves by 12/08 and ~15 tcfe by 12/09 #1 gas resource play 45 tcfe of risked unproved reserve potential; >10-year drilling inventory of 33,000 net drilling locations #1 inventory of U.S. onshore leasehold and 3-D seismic 14.8 mm net acres of U.S. onshore leasehold and 20.8 mm acres of 3-D seismic data 2 Data above incorporates: CHK s spending and production forecast as of 9/22/08 6/30/08 information pro forma for PXP Haynesville Shale and BP Fayetteville Shale and Woodford Shale transactions Risk disclosure regarding unproved reserve estimates appears on page 30

3 Financial Highlights $40.1 billion enterprise value $27.3 billion equity value, $12.2 billion net long-term debt and $0.6 billion working capital deficit Strong profitability 2009E: ebitda $6.3 billion, operating cash flow $5.9 billion, net income to common $2.2 billion Great value to investors 2009E multiples: 4.6x operating cash flow, 6.3x ebitda, 12.6x P/E ratio Trading at a discount to estimated net asset value per share Great stock price performance CHK up ~34-fold in 15 years as a public company, #2 performer among large-cap E&P companies during that period; CHK up ~15% year-to-date despite big 2008 third quarter sector pullback Well hedged 83% of LH 08, 72% of 2009 and 46% of 2010 production hedged at average prices of $9.30, $9.63 and $9.89 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/?? in Marcellus Shale, hope to announce a transaction by year-end 2008 Anticipating substantial balance sheet improvement by year-end 2010 Strong asset growth and earnings growth expected over the next two years Recently reduced drilling capex by ~$3.2 billion, or 17% Expect to primarily direct ~$2.0 billion of excess cash generation in 09 and 10 to debt reduction Data above incorporates: CHK s spending and production forecast and realized and locked gains as of 9/22/08 Reconciliations to GAAP measures appear on pages 18 and 19 Summary of hedging positions appear on page 21 An assumed common stock price of $45.00, NYMEX prices of $9.00/mcf and $110.00/bbl for 2009 and excludes effects of FAS 133 (unrealized hedging gain or loss) CHK large-cap peers include APA, APC, DVN, ECA, EOG, NBL, and XTO 3

4 What s CHK? Drilling capex budget through 10 reduced by ~$3.2 billion, or 17% $1.3 billion reduction attributable to $800mm BP Fayetteville Shale carry and anticipated $500mm carry in potential Marcellus Shale JV $1.9 billion attributable to reduced drilling activity Helps allow U.S. natural gas demand growth to catch up to U.S. natural gas supply growth Production growth forecast lowered to 18% from 21% for 2008 and to 16% from 19% for 2009 and 2010 Forecast lowered due to reduced drilling capex, planned volumetric production payment (VPP) sales and temporary production curtailments due to gas processing facility limitations from hurricane Ike and low Mid- Continent well head gas prices Closed Fayetteville Shale 25% JV transaction with BP Received $1.1 billion in cash and will receive a further $800 million through a drilling capex carry during the remainder of 2008 and in 2009 Resumed plans to sell a minority interest in midstream business for $1.0 billion to institutional investors Proceeds to be used to fund a portion of the costs to build out infrastructure in various shale plays, particularly the Haynesville Shale Also, in the process of finalizing a $500 million revolving credit facility for midstream business 4

5 CHK s Distinctive Business Strategy

6 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 Leading 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 5th 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 7,200 Now moving to advance present value forward through asset monetizations via VPP s and promoted partnerships 6

7 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 to secure strong profit 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 7,200 total employees, including 1,800 geoscience, engineering and operations department employees The nation s most active drilling program with 157 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 7

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

9 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 Fayetteville Shale Lower Huron & Other Appalachia Marcellus Shale Eastern Overthrust Belt Counties with CHK leasehold Barnett and Woodford Shale Plays Delaware Basin Laramide Thrust Belt Permian Basin South Texas Barnett Shale Ouachita Thrust Belt Texas Gulf Coast Haynesville Shale Ark-La-Tex Alabama Shales Mississippian & Devonian black shales Thrust Belt CHK field offices CHK OKC headquarters CHK operated rigs (157) Scale: 1 inch = 275 miles CHK non-operated rigs (91) 9

10 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 11.8 tcfe of proved reserves, 93% gas 45 tcfe of risked unproved reserves 144 tcfe of unrisked unproved reserves 14.8 million net acres of leasehold 20.8 million acres of 3-D seismic data >10-year inventory of ~33,000 net drillsites Conventional gas resource Unconventional gas resource Net Acreage 14.8 million acres 4.3 Proved Undeveloped Reserves 3.9 tcfe 0.9 Drillsites ~33,000 net drillsites 5, ,900 Risked Unproved Reserves 45.3 tcfe As of 6/30/08, pro forma for PXP Haynesville Shale and BP Fayetteville Shale and Woodford Shale transactions Risk disclosure regarding unproved reserve estimates appears on page 30

11 CHK Became the Largest U.S. Natural Gas Producer in 2Q 08 Daily U.S. Natural Gas Production (a,b) Q'08 2Q'08 Reported U.S. Proved U.S Drilling at Production vs. 1Q'08 vs. 2Q'07 Net Proved Gas Gas Reserve RP U.S. Rigs Ranking Company (c) Ticker 2Q'08 1Q'08 2Q'07 % Change % Change Reserves Ranking Ratio (d) 8/22/08 (e) 1. Chesapeake CHK 2,143 2,063 1, % 25.0% 10, BP BP 2,140 2,149 2,165 (0.4%) (1.2%) 15, ConocoPhillips COP 2,132 2,063 2, % (8.1%) 12, Devon DVN 1,939 1,878 1, % 14.0% 7, Anadarko APC 1,869 2,137 1,798 (12.5%) 3.9% 8, XTO XTO 1,795 1,708 1, % 34.9% 9, Chevron CVX 1,588 1,666 1,703 (4.7%) (6.8%) 3, EnCana ECA 1,629 1,552 1, % 25.0% 6, ExxonMobil XOM 1,274 1,305 1,517 (2.4%) (16.0%) 13, EOG EOG 1,139 1, % 18.6% 4, Williams WMB 1,110 1, % 23.6% 4, Shell RDS 1,096 1,105 1,091 (0.8%) 0.5% 2, Apache APA % (5.4%) 2, El Paso EP (0.3%) 3.7% 3, Occidental OXY % (1.1%) 2, Southwestern SWN % 78.4% 1, Newfield NFX % (22.3%) 1, Marathon MRO (10.6%) (6.3%) 1, Noble NBL % (3.8%) 1, Questar STR % 15.6% 1, Totals / Average 24,132 23,905 22, % 8.6% 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 2Q 08 production Source: Smith International Survey (operated rig count) 11

12 What s New in the Haynesville Shale? CHK s largest discovery and expected to become the largest U.S. natural gas field CHK has been evaluating the play for 2 years Extensively analyzed the play in CHK geoscience department, including data on over 100 wells that have penetrated the formation CHK began drilling in 3Q 06 Evaluated cores in early 2007 at CHK s state-of-the-art Reservoir Technology Center (RTC) Now have 14 Haynesville Shale horizontal wells producing Initial production (IP) rates on horizontal wells have ranged from 5 mmcfe net to 15 mmcfe/day on restricted chokes at flowing casing pressures of up to 6,500 PSI; last three wells average IP rates >10 mmcfe/day Anticipate reaching at least 75 mmcfe net/day by year-end 08 Based on drilling results by CHK and others in the play, believe that an EUR range of bcfe per well for the Core Area is reasonable with mid-point of 6.5 bcfe Currently own or have commitments for 480,000 net acres of leasehold (after PXP 20% sale of 120,000 net acres) 12 Note: Risk disclosure regarding unproved reserve estimates appears on page 30

13 What s New in the Barnett Shale? 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 During 2Q 08 CHK s average daily net production of 466 mmcfe was up 125% from 2Q 07 and up 13% sequentially Currently producing ~530 mmcfe/day net Anticipate reaching ~675 mmcfe/day net by YE 2008 Have improved drilling efficiency and reduced average days to drill from days to days Currently operating ~38 rigs to further develop 280,000 net acres of leasehold, of which 240,000 net acres are located in the prime Core and Tier 1 areas Industry leading urban-drilling expertise has become a significant competitive advantage Should finish leasing campaign in 2010 with ,000 total net acres under lease, of which ,000 should be in the prime Core and Tier 1 areas 13 Note: Risk disclosure regarding unproved reserve estimates appears on page 30

14 What s New in the Fayetteville Shale? Recently closed Fayetteville Shale 25% joint venture transaction with BP Received $1.1 billion in cash and will receive a further $800 million through a drilling capex carry during the remainder of 2008 and 2009 Play keeps getting better Average IP rates continue to improve Current net production at ~135 mmcfe/day (following sale of 45 mmcfe/d to BP); anticipate reaching 180 mmcfe/day by year-end 2008 Per well drilling costs on the decline Unit service costs substantially lower due to increased industry capacity Experiencing greater economies of scale and even further along the learning curve Boosting drilling to hold leasehold and accelerate PV creation Currently operating 22 rigs Own ~415,000 net acres of leasehold in the Core Area of the play Could drill up to 5,200 wells at 2.4 bcfe per well on average 14 Note: Risk disclosure regarding unproved reserve estimates appears on page 30

15 What s New in Appalachia? CHK realized the potential of Appalachia earlier than any other large-cap E&P Acquired CNR for just $2.2 billion in 2005 CNR provided land foundation of 3.5 million net acres; now own over 4 million net acres December 2007 VPP transaction monetized nearly half our cash investment CHK Marcellus leasehold now 1.6 mm net acres and growing Lower Huron showing potential; have ~1.2 mm net acres Have drilled over 30 vertical and horizontal Marcellus and Lower Huron wells to date Two 2Q 08 horizontal Marcellus Shale wells had initial gross production rates of 7 mmcfe/day and combined estimated EUR of ~11 bcfe CHK looking to do a joint venture for 25% of its interest in the Marcellus Shale similar to PXP and BP transactions; discussions underway with multiple parties 15 Note: Risk disclosure regarding unproved reserve estimates appears on page 30

16 Financial Overview

17 Strong Cash Margins and Steady Debt Levels per Mcfe $ / mcfe $9.50 $9.00 $8.50 $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 Net cash margin Preferred dividends Interest expense (1) (2) G&A Production tax Production expense Long term debt/mcfe of proved reserves Sr. Unsecured Q08 2Q08 Rating B3/B B2/B B1/B+ B1/B+ Ba3/BB- Ba3/BB- Ba2/BB Ba2/BB Ba3/BB Ba3/BB Ba3/BB 2Q 08 Averages (per mcfe) Realized price: $8.55 2Q 08 net cash margin: $6.33 Preferred dividends: $0.04 Interest expense: $0.36 G&A: $0.38 Production tax: $0.41 Production expense: $1.03 Total cash costs = $ (1) Excludes unrealized gains/losses on interest rate derivatives (2) Excludes non-cash stock based compensation

18 2008 Financial Projections at Various Natural Gas Prices ($ in millions; oil at $ NYMEX) $7.00 $8.00 $9.00 $10.00 $11.00 O/G revenue 846 bcfe (1) $7,544 $7,719 $7,894 $8,069 $8,244 Hedging effect (2) (103) (263) (427) (592) (761) Marketing and other (@ $0.15/mcfe) Production taxes 5% (338) (347) (355) (364) (373) LOE (@ $1.05/mcfe) (888) (888) (888) (888) (888) G&A (@ $0.46/mcfe) (3) (389) (389) (389) (389) (389) Ebitda 5,953 5,959 5,962 5,963 5,960 Interest (@ $0.38/mcfe) (317) (317) (317) (317) (317) Operating cash flow (2)(3)(4) 5,636 5,642 5,645 5,646 5,643 Oil and gas depreciation (@ $2.35/mcfe) (1,988) (1,988) (1,988) (1,988) (1,988) Depreciation of other assets (@ $0.22/mcfe) (186) (186) (186) (186) (186) Income taxes (38.5% rate) (1,333) (1,335) (1,336) (1,337) (1,336) Net income to common (1) $2,129 $2,133 $2,135 $2,135 $2,133 Net income to common per fully diluted shares $3.75 $3.76 $3.76 $3.76 $3.76 Net debt/ ebitda (5) 2.1x 2.1x 2.1x 2.1x 2.1x Debt to book capitalization ratio 42% 42% 42% 42% 42% Ebitda/fixed charges (including pfd. dividends) (6) 9.6x 9.6x 9.6x 9.6x 9.6x MEV/operating cash flow (7) 4.8x 4.8x 4.8x 4.8x 4.8x EV/ebitda (8) 6.7x 6.7x 6.7x 6.7x 6.7x PE ratio (9) 12.0x 12.0x 12.0x 12.0x 12.0x (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 ($619mm) = interest expense of $586 million plus dividends of $33 million (7) MEV (Market Equity Value) = $27.3 billion ($45.00/share x 606 mm fully diluted shares pro forma for July 2008 equity offering) (8) EV (Enterprise Value) = $40.1 billion (Market Equity Value, plus $12.2 billion in pro forma net long-term debt and $0.6 billion working capital deficit) (9) Assuming a common stock price of $45.00/share 18

19 2009 Financial Projections at Various Natural Gas Prices ($ in millions; oil at $ NYMEX) $7.00 $8.00 $9.00 $10.00 $11.00 O/G revenue 975 bcfe (1) $6,794 $7,587 $8,381 $9,175 $9,969 Hedging effect (2) (203) (783) (1,402) Marketing and other (@ $0.15/mcfe) Production taxes 5% (340) (379) (419) (459) (498) 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 6,029 6,181 6,335 6,509 6,645 Interest (@ $0.43/mcfe) (414) (414) (414) (414) (414) Operating cash flow (2)(3)(4) 5,615 5,767 5,921 6,095 6,231 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) (1,235) (1,293) (1,352) (1,419) (1,472) Net income to common (1) $1,971 $2,065 $2,160 $2,267 $2,350 Net income to common per fully diluted shares $3.27 $3.43 $3.58 $3.76 $3.90 Net debt/ebitda (5) Debt to book capitalization ratio 38% 37% 37% 37% 37% Ebitda/fixed charges (including pfd. dividends) (6) MEV/operating cash flow (7) 4.9x 4.7x 4.6x 4.5x 4.4x EV/ebitda (8) 6.7x 6.5x 6.3x 6.2x 6.0x PE ratio (9) 13.8x 13.1x 12.6x 12.0x 11.5x (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 ($619mm) = interest expense of $586 million plus dividends of $33 million (7) MEV (Market Equity Value) = $27.3 billion ($45.00/share x 606 mm fully diluted shares pro forma for July 2008 equity offering) (8) EV (Enterprise Value) = $40.1 billion (Market Equity Value, plus $12.2 billion in pro forma net long-term debt and $0.6 billion working capital deficit) (9) Assuming a common stock price of $45.00/share 19

20 2010 Financial Projections at Various Natural Gas Prices ($ in millions; oil at $ NYMEX) $7.00 $8.00 $9.00 $10.00 $11.00 O/G revenue 1,130 bcfe (1) $7,937 $8,861 $9,785 $10,710 $11,634 Hedging effect (2) (426) (905) Marketing and other (@ $0.15/mcfe) Production taxes 5% (409) (456) (504) (552) (599) 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 6,789 7,217 7,620 8,026 8,424 Interest (@ $0.38/mcfe) (424) (424) (424) (424) (424) Operating cash flow (2)(3)(4) 6,365 6,793 7,196 7,602 8,000 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) (1,398) (1,562) (1,718) (1,874) (2,027) Net income to common (1) $2,232 $2,496 $2,743 $2,993 $3,238 Net income to common per fully diluted shares $3.64 $4.08 $4.48 $4.89 $5.29 Net debt/ebitda (5) Debt to book capitalization ratio 32% 32% 32% 32% 31% Ebitda/fixed charges (including pfd. Dividends) (6) MEV/operating cash flow (7) 4.3x 4.0x 3.8x 3.6x 3.4x EV/ebitda (8) 5.9x 5.6x 5.3x 5.0x 4.8x PE ratio (9) 12.4x 11.0x 10.0x 9.2x 8.5x (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 ($617mm) = interest expense of $586 million plus dividends of $31 million (7) MEV (Market Equity Value) = $27.3 billion ($45.00/share x 606 mm fully diluted shares pro forma for July 2008 equity offering) (8) EV (Enterprise Value) = $40.1 billion (Market Equity Value, plus $12.2 billion in pro forma net long-term debt and $0.6 billion working capital deficit) (9) Assuming a common stock price of $45.00/share 20

21 Successful Hedging Reduces Risk and Helps Secure Attractive Cash Margins CHK s natural gas and oil hedge positions for (1)(2) Natural Gas Swaps (3) % Hedged NYMEX Avg. Price 3Q'08 83% $8.90 4Q'08 79% $9.33 3Q-4Q 2008 Total 81% $ Total 65% $ Total 45% $9.70 % Hedged 3Q'08 70% 4Q'08 60% 3Q-4Q 2008 Total 65% 2009 Total 70% 2010 Total 37% Oil (5) NYMEX Avg. Price $76.45 $77.57 $76.97 $82.33 $90.25 Natural Gas Collars (4) % Hedged NYMEX Avg. Floor Price Nymex Avg. Ceiling Price 3Q'08 4% $8.17 $ Q'08 3% $8.04 $ Q-4Q 2008 Total 4% $8.11 $ Total 7% $8.05 $ Total 2% $7.71 $11.46 NYMEX Strip 9/19/08 3Q - 4Q Year Average Oil $ $ $ $ $ $ Gas $ 9.05 $ 8.49 $ 8.75 $ 8.61 $ 8.42 $ 8.66 (1) Excludes written calls (2) Includes CNR derivative liabilities assumed at MTM value upon closing. Assumes approximately the midpoint of company production forecast as of 9/22/08 each item and includes hedging positions as of 9/22/08 (3) Includes positions with knockout provisions, but does not include calls written for average premium of $0.78 at average strike price of $10.32 in 2H 08, $0.61 and $11.37 in 2009 and $0.72 and $10.77 in 2010 (4) Includes three-way collars (5) Includes cap-swaps and knockout swaps 21

22 Cash Resource Plan (1) Cash Resources ($ in millions) 2008E 2009E 2010E Total Operating cash flow (1)(2) $5,550 - $5,750 $5,650 - $6,250 $6,500 - $7,100 $17,700 - $19,100 Sale of leasehold and producing properties 6,550-6,850 1,750-2, ,250 9,050-10,350 Sale of producing properties via VPP's 1,775-1,875 1,100-1,300 1,100-1,300 3,975-4,475 Debt and equity offerings 4, ,730 Midstream financings 850-1, ,150-2,800 Proceeds from investments and other ,200-1,400 Total: $19,730 - $20,630 $9,925 - $11,475 $9,150 - $10,750 $38,805 - $42,855 Cash Uses ($ in millions) Drilling $5,500 - $5,700 $4,500 - $5,000 $5,000 - $5,500 $15,000 - $16,200 Acquisition of leasehold and producing properties 8,500-9,500 2,000-2,250 1,250-1,750 11,750-13,500 Geologic and geophysical costs Compression & other PPE 1,000-1, ,750-1,900 Midstream infrastructure 1,200-1,250 1,350-1, ,300-3,700 Dividends, Sr. Notes redemption, capitalized interest, etc. 1,150-1, ,225-2,400 Cash income taxes ,050 Total: $18,000 - $19,500 $9,350 - $10,475 $8,175 - $9,625 $35,525 - $39,600 Net Cash Change $1,130-1,730 $575-1,000 $975-1,125 $3,255-3,280 Revolving credit facility ($ in millions) Beginning balance $2,000 $600 $0 Potential change ($1,400) ($600) $0 Ending balance $600 $0 $0 Production (bcfe per day) Proved reserves (tcfe) Proved reserves per fully diluted share (mcfe) YOY % change in proved reserves per FD share 19% 15% 13% Long-term debt ($ in millions) $11,425 $10,650 $9,600 Long-term debt per mcfe of proved reserves $0.88 $0.71 $ (1) From Outlook as of September 22, 2008 and assumes the midpoint of company guidance and NYMEX prices of $7.50-$8.50/mcf and $110/bbl. (2) Before changes to asset and liabilities. Reconciliations to GAAP measures appear on pages 18, 19 and 20

23 Summary

24 CHK Offers Compelling Net Asset Value/Share As of June 30, Pro Forma various NYMEX gas prices (1)(2) Average NYMEX Natural Gas Prices ($ in millions, except per share $6.00 $7.00 $8.00 $9.00 $10.00 $11.00 Proved reserves $ 21,300 $ 25,400 $ 29,500 $ 33,600 $ 37,600 $ 41,700 Unproved reserves (3) 27,200 31,700 36,200 40,800 45,300 49,800 Value of CHK hedges 1,900 2,800 1,400 - (1,400) (3,100) Value of CNR hedges - (100) (100) (200) (200) (200) Other assets (4) 4,000 4,000 4,000 4,000 4,000 4,000 PXP and BP future drilling cost receivables 2,450 2,450 2,450 2,450 2,450 2,450 Less: pro forma long-term debt (5) (12,100) (12,100) (12,100) (12,100) (12,100) (12,100) Less: preferred stock (when not dilutive) Less net working capital (600) (600) (600) (600) (600) (600) Shareholder value $ 44,150 $ 53,550 $ 60,750 $ 67,950 $ 75,050 $ 81,950 Fully diluted common shares (in millions) (5)(6) NAV per share $ $ $ $ $ $ Potential % upside (6) 62% 96% 123% 149% 175% 201% Asset value to long-term debt 4.6x 5.4x 6.0x 6.6x 7.2x 7.8x Leasehold Transaction Implied Values Undrilled Implied Shale Implied Shale NYMEX Strip 9/19/08 Acres Net Leasehold Leasehold Value Oil Gas Plays to CHK Value/Acre ($ in billions) 3Q - 4Q 2008 $ $ 9.05 Haynesville Shale via PXP sale 480,000 $30,000 $ $ $ 8.49 Fayetteville Shale via BP sale 400,000 $12,000 $ $ $ 8.75 Fort Worth Barnett Shale Core & Tier 1 200,000 $30,000 $ $ $ 8.61 Marcellus Shale 1,600,000 $7,500 $ $ $ 8.42 All other plays 9,770,000 $1,000 $9.8 Total 12,450,000 $3,773 $ Year Average $ $ 8.66 (1) NYMEX natural gas price scenarios and NYMEX oil price held constant at $ per bbl (2) Pro forma for PXP Haynesville Shale and BP Fayetteville Shale and Woodford Shale transactions and 3Q 08 leasehold acquisitions (3) 45 tcfe of unproved reserves valued from $0.60-$1.10/mcfe (4) Buildings, drilling rigs, midstream gas assets at net book value and investments at market value (5) Pro forma for July 2008 equity offering, 7.75% senior note redemption (6) Based on common stock price of $45.00 per share 24

25 Why Buy CHK? Growth 28 consecutive quarters of organic production growth; total production growth of 23% in 07; projecting increases of 18% in 08 and 16% in 09 and 10 Sustainability 57 tcfe of proved and risked unproved reserves; >10-year drilling backlog of ~33,000 net drillsites across multiple gas resource plays Value Trade at a substantial discount to estimated NAV Gas Focus Purest play in U.S. natural gas; largest producer of U.S. natural gas Performance #2 large-cap E&P stock price performer since 2/93 IPO Diversified Risk Uniquely focused business strategy; well-diversified, all-onshore U.S. asset base Hedging Successful track record of locking in margins and investment returns during past five years Income Pay a $0.30 annual common stock dividend (increased in 6/08 by 11%) Commitment Sizeable insider ownership 25 Reflects CHK s spending and production forecast and realized and locked gains as of 9/22/08 Risk disclosure regarding unproved reserve estimates appears on page 30

26 Appendix

27 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 27

28 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 28

29 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 7.0% Senior Notes Due 2014 #165167BJ5 CHKA % 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 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 Contacts: Jeffrey L. Mobley, CFA Senior Vice President Investor Relations and Research (405) Marcus C. Rowland Executive Vice President and Chief Financial Officer (405) (1) ISIN #

30 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 producible 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 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. 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 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 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. 31