December 2008 Investor Presentation

Transcription

1 December 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 2,214mmcf/day 214mmcf/day and 2010E 2,515 mmcf/day #1 driller in U.S. ~130 operated rigs currently, on the way down to ~ operated rigs until gas markets rebalance, ~85 non-operated rigs, ~15 info only rigs; collector of ~12% 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 5-10% in 09 and 10-15% in 10 to 2.4 and 2.7 bcfe/day, respectively #1 large-cap proved reserve growth 12.1 tcfe estimated proved reserves at 9/30/08; targeting tcfe of proved reserves by 12/08, tcfe by 12/09, and tcfe by 12/10 #1 gas resource play 55 tcfe of risked unproved reserve potential; >10-year drilling inventory of 35,500 net drilling locations #1 inventory of U.S. onshore leasehold and 3-D seismic 15.0 mm net acres of U.S. onshore leasehold and 20.8 mm acres of 3-D seismic data 2 Data above incorporates: Information as of 9/30/08 - Pro forma for Marcellus Shale JV with StatoilHydro in 4Q 08 CHK s Outlook as of 12/7/08 Risk disclosure regarding unproved reserve estimates appears on page 34

3 Financial Highlights $22.2 billion enterprise value $9.1 billion equity value, $10.8 billion net long-term debt, plus $0.5 billion preferred stock and $1.8 billion working capital deficit Strong profitability 2009E: ebitda $5.2 billion, operating cash flow $4.8 billion, net income to common $1.6 billion Well hedged 71% of 4Q 08, 74% of 2009 and 48% of 2010 production hedged at average prices of $9.00, $8.48 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: $3.4 billion for 32.5% interest Prudent balance sheet Net debt to cap ratio of 43% at 9/30/08; anticipating ~40% by 12/08 and ~34% by 12/09 Staggered maturities with low fixed rates; first maturity in November 2012 Strong asset and cash flow coverage of debt Anticipating substantial balance sheet improvement Substantial asset growth, cash generation and earnings set to meaningfully deleverage CHK by YE 09 Since July 2008, CHK reduced drilling and leasehold and producing property acquisition capex by ~$10.0 billion, or ~58% Great value to investors 2009E multiples: 1.9x operating cash flow, 4.3x ebitda, 5.6x P/E ratio Trading at steepest discount to estimated net asset value per share & lowest earnings multiples ever 3 Data above incorporates: CHK s Outlook as of 12/7/08 Pro forma for Marcellus Shale JV with StatoilHydro and conversion of $765 million of senior notes for $24 million common shares in 4Q 08 Reconciliations to GAAP measures appear on page 23 Summary of hedging positions appear on page 26 An assumed common stock price of $15.00, NYMEX prices of $7.00/mcf and $70.00/bbl and excludes effects of FAS 133 (unrealized hedging gain or loss)

4 Financial and Operational Update Proactive Cash Flow Management CHK continues to proactively adapt to changing market conditions Reduced 2009 and 2010 capital spending plans on 12/7/08 to achieve e a cash neutral budget over the next two years that does not depend on future asset sales Further reduced drilling budget by $2.9 billion, or 31%, and leasehold and acquisition budget by $2.2 billion, or 78%, relative to 11/3/08 Outlook Have reduced spending plans four times in the last four months in response to lower natural gas and oil prices and turbulent financial markets Since July 2008, CHK has reduced its 2009 and 2010 spending plans for drilling, leasehold & producing property acquisitions by ~$10 billion, or 58% CHK operated rig count has decreased from 158 rigs in 8/08 to 130 rigs currently and will be further reduced to rigs in early 1Q 09, when approximately half of its rigs paid fully or partially paid for by its JV partners Now targeting production growth of 5-10% in 2009 and 10-15% in 2010 Planning to build up to $4 billion in additional cash resources by year-end 2010 through further asset monetizations VPPs and/or sales of producing properties Leasehold sales or JVs Midstream system sales or equity partner investments 4

5 Financial and Operational Update Asset Monetizations on the Horizon In discussions to sell CHK s fourth VPP on properties in the Anadarko and Arkoma Basins ~100 bcfe of proved reserves Current net production of ~55 mmcfe/day ~$450 million in cash proceeds, or $4.50/mcfe Working to close by year-end 2008 Intend to market CHK s fifth VPP on all or a portion of South TX producing properties Received multiple bids for entire asset package, but believe a VPP transaction will yield a better value proposition ~80 bcfe of proved reserves Current net production of ~70 mmcfe/day ~$450 million in cash proceeds, or $5.60/mcfe Working to close in 1Q 09 In discussions with multiple parties for either a minority investment in CHK s midstream operations or the purchase of a portion of existing systems in 1Q 09 5

6 Financial and Operational Update Hedge Protection and Cost Advantages Restructured hedge positions substantially protects 2009 cash flow ~76% of anticipated 2009 natural gas production hedged through swaps and collars with a floor of $8.20 per mcfe Only 12% of anticipated production hedged through swaps with knock out provisions, much of which is concentrated in 4Q 09 Anticipating substantially lower drillbit finding and development costs for CHK in 2009 through: Joint venture drilling carries 10-20% lower oilfield service costs Continued operational excellence Targeting ~2.5 tcfe of proved reserve additions in 2009 from ~$3 billion of net drilling capital, which would imply a production replacement rate of >250% and a cost of ~$1.20/mcfe Includes the benefit of drilling carries in CHK s three shale JVs, with ~1.1 tcfe of proved reserve additions from $500 million in net drilling capital at a cost of ~$0.45/mcfe 6

7 Financial and Operational Update Liquidity and Filings with the SEC CHK has ample current and projected financial liquidity ~$1.5 billion in cash and cash equivalents on hand in early December 08 Targeting ~$2 billion in cash and cash equivalents by year-end end 2008 if successful in completing CHK s fourth VPP Managing business to a cash neutral budget that is not dependent on future asset sales On 11/26/08, CHK filed registration statements and distribution agency agreements with the SEC in order to create broad financial i flexibility for an uncertain economic and commodity market environment over the next few quarters We underestimated how the market would assess the purpose, implication, timing and magnitude of our filings; we made a mistake In response, we have terminated our distribution agency agreement with three securities firms and have amended our acquisition shelf registration statement on Form S-4 to reduce common shares registered from 50 million to 25 million In 4Q 08 08, CHK converted $765 million of convertible senior notes for ~24 million common shares At face value of convertible senior notes, effective issue price of ~$32 per share After considering the elimination of existing dilution potential in the notes, effective issue price of >$40 per share (1) 7 1) Assumes common stock price >$75 per share at maturity of convertible senior notes

8 CHK s Distinctive Business Strategy

9 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 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 In 2008, CHK has monetized producing assets and undeveloped leasehold that had a cost basis of ~$3 billion for $11.7 billion in cash and drilling carries for a profit of ~$8.7 billion Now moving to advance present value forward through asset monetizations via VPP s and promoted partnerships 9

10 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, vertically-integrated natural gas manufacturing machine is well positioned for future growth Industry-leading leasehold acquisition program 7,600 total employees, including 1,800 geoscience, engineering and operations department employees The nation s most active drilling program with 130 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 10

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

12 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 (~130) Scale: 1 inch = 275 miles CHK non-operated rigs (~85) 12

13 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 54.6 tcfe of risked unproved reserves 15.0 million net acres of leasehold 20.8 million acres of 3-D seismic data >10-year inventory of ~35,500 net drillsites Net Acreage 15.0 million acres 4.6 Drillsites ~35,500 net drillsites 5, , tcfe of unrisked unproved reserves Proved Undeveloped Risked Unproved Reserves Reserves 4.1 tcfe 54.6 tcfe Conventional gas resource Unconventional gas resource As of 9/30/08 - Pro forma for recent Marcellus Shale JV with StatoilHydro Risk disclosure regarding unproved reserve estimates appears on page 34

14 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 Haynesville Shale #1 480, , ,400 14,600 29, Marcellus Shale #1 1,200, , ,600 11,630 46, 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 6,187,000 Various 7,800 Various 2,310 5,300 7,610 36, Unconventional Sub-total 10,400,000 30,000 8,345 49,400 57, ,200 1,530 Total 15,000,000 35,500 12,055 54,600 66, ,800 2, As of 9/30/08 - Pro forma for recent Marcellus Shale JV with StatoilHydro Risk disclosure regarding unproved reserve estimates appears on page 34

15 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) 11/28/08 (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, , (1.3%) 18.4% 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) 15

16 What s New in the Haynesville Shale? 90 Miles 100 Miles 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 9/30/08 net production of ~50 mmcfe/day (~65 mmcfe gross) 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 CHK Horizontal ~3,000 potential net risked wells in inventory to Producing Wells Industry Horizontal Horizontal Rigs develop 14 tcfe of risked unproved reserves Producing Wells Chesapeake Currently have 130 bcfe of PUD reserves Haynesville Penetrations CHK Acreage Horizontal Rigs Industry Area Within Outline = 3.5 Million Acres 16 Note: Risk disclosure regarding unproved reserve estimates appears on page 34

17 What s New in the Barnett Shale? 67 Miles Core & Tier 1 Outline 82 Miles g 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 9/30/08 net production of ~560 mmcfe/day is up ~37% YTD Have improved drilling efficiency and reduced avg. days to drill from days to days Planning to operate an average of ~26 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 17 Note: Risk disclosure regarding unproved reserve estimates appears on page 34

18 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 an average of ~20 rigs in 2009 to further develop ~415,000 net acres of leasehold ld 9/30/08 net production of ~145 mmcfe/day is up ~46% YTD ~3,700 potential net risked wells in inventory to develop = ~7.1 tcfe of PUD and risked unproved reserves ~9 tcfe of PUD and unrisked unproved reserves Closed sale of 25% interest in ~540,000 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 18 Note: Risk disclosure regarding unproved reserve estimates appears on page 34

19 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 ~1.2 million net acres of leasehold and plan to operate up to 15 rigs by YE 09 9/30/08 net production of ~15 mmcfe/day is up ~300% YTD CHK sold a 32.5% interest in CHK s Marcellus Shale assets in Appalachia to StatoilHydro for $ billion CHK received $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 Transaction closed on 11/24/08 19 Note: Risk disclosure regarding unproved reserve estimates appears on page 34

20 Financial Overview

21 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

22 Senior Note Maturity 9/30/08 / $4,000 $3,600 $3,200 Total Senior Notes: $10.1 billion Average Rate: 5.6% Average Maturity: 8.3 years $3,323 (1) $2,800 $2,400 $2,526 (1) $ in MM $2,000 $1,600 $1,200 $800 $400 Bank credit facility matures November 2012 $864 $600 $1,270 $1,051 (1) $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 and pro forma for conversion of $765 million of convertible senior notes for 24 million common shares i in 4Q % 22 Staggered long term debt maturity structure with no senior notes due for five years; cash flow of >$30 billion likely before first payment

23 2009 Financial Projections at Various Natural Gas Prices As of 12/7/08 Outlook ($ in millions; oil at $70.00 NYMEX) $5.00 $6.00 $7.00 $8.00 $9.00 O/G revenue 880 bcfe (1) $4,338 $5,050 $5,761 $6,473 $7,185 Hedging effect (2) , , , Marketing and other (@ $0.15/mcfe) Production taxes 5% (217) (252) (288) (324) (359) LOE (@ $1.15/mcfe) (1,012) (1,012) (1,012) (1,012) (1,012) G&A (@ $0.46/mcfe) (3) (405) (405) (405) (405) (405) Ebitda 4,496 4,779 5,203 5,430 5,676 Interest (@ $0.43/mcfe) (374) (374) (374) (374) (374) Operating cash flow (2)(3)(4) 4,122 4,405 4,829 5,056 5,302 Oil and gas depreciation (@ $2.25/mcfe) (1,980) (1,980) (1,980) (1,980) (1,980) Depreciation of other assets (@ $0.22/mcfe) (194) (194) (194) (194) (194) Income taxes (38.5% rate) (750) (859) (1,022) (1,110) (1,205) Net income to common (1) $1,198 $1,372 $1,633 $1,772 $1,923 Net income to common per fully diluted shares $1.98 $2.27 $2.70 $2.93 $3.18 Net debt/ebitda (5) Debt to book capitalization ratio 34% 34% 34% 33% 33% Ebitda/fixed charges (including pfd. dividends) (6) MEV/operating cash flow (7) 2.2x 2.1x 1.9x 1.8x 1.7x EV/ebitda (8) 5.0x 4.7x 4.3x 4.1x 3.9x PE ratio (9) 76x 7.6x 66x 6.6x 56x 5.6x 51x 5.1x 47x 4.7x (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 ($590mm) = interest expense of $566 million plus dividends of $24 million (7) MEV (Market Equity Value) = $9.1 billion ($15.00/share x 607 mm fully diluted shares as of 09/30/08; pro forma for conversion of $765 million of convertible senior notes for 24 million shares in 4Q 08) (8) EV (Enterprise Value) = $22.2 billion (Market Equity Value, plus $10.8 billion of net long-term debt plus $0.5 billion preferred stock treated as debt and $1.8 billion working capital deficit) (9) Assuming a common stock price of $15.00/share 23

24 2010 Financial Projections at Various Natural Gas Prices As of 12/7/08 Outlook ($ in millions; oil at $80.00 NYMEX) $5.00 $6.00 $7.00 $8.00 $9.00 O/G revenue 996 bcfe (1) $5,005 $5,811 $6,618 $7,424 $8,230 Hedging effect (2) , Marketing and other (@ $0.15/mcfe) Production taxes 5% (258) (299) (341) (382) (424) LOE (@ $1.20/mcfe) (1,195) (1,195) (1,195) (1,195) (1,195) G&A (@ $0.46/mcfe) (3) (458) (458) (458) (458) (458) Ebitda 4,010 4,949 6,104 6,468 6,806 Interest (@ $0.38/mcfe) (374) (374) (374) (374) (374) Operating cash flow (2)(3)(4) 3,636 4,575 5,730 6,094 6,432 Oil and gas depreciation (@ $2.20/mcfe) (2,191) (2,191) (2,191) (2,191) (2,191) Depreciation of other assets (@ $0.22/mcfe) (219) (219) (219) (219) (219) Income taxes (38.5% rate) (472) (833) (1,278) (1,418) (1,548) Net income to common (1) $754 $1,332 $2,042 $2,266 $2,474 Net income to common per fully diluted shares $1.23 $2.17 $3.33 $3.69 $4.03 Net debt/ebitda (5) Debt to book capitalization ratio 27% 27% 26% 26% 26% Ebitda/fixed charges (including pfd. Dividends) (6) MEV/operating cash flow (7) 2.5x 2.0x 1.6x 1.5x 1.4x EV/ebitda (8) 5.6x 4.5x 3.6x 3.4x 3.3x PE ratio (9) 12.2x 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 ($588mm) = interest expense of $566 million plus dividends of $22 million (7) MEV (Market Equity Value) = $9.1 billion ($15.00/share x 607 mm fully diluted shares as of 09/30/08; pro forma for conversion of $765 million of convertible senior notes for 24 million shares in 4Q 08) (8) EV (Enterprise Value) = $22.2 billion (Market Equity Value, plus $10.8 billion of net long-term debt, plus $0.5 billion preferred stock treated as debt and $1.8 billion working capital deficit) (9) Assuming a common stock price of $15.00/share 24

25 Cash Resource Plan 4Q (1) Net Cash Resources ($ in millions) Q4'08E 2009E 2010E Total Operating cash flow (1)(2) $1,250 - $1,300 $4,800 - $5,100 $5,700 - $6,100 $11,750 - $12,500 Leasehold and producing properties transactions Sales 1,400-1, , ,000 2,400-3,450 Volumetric Production Payments , ,775-1,975 Acquisitions (900-1,000) ( ) ( ) (1,450-1,650) Net leasehold and producing properties transactions ,100-1, ,200 2,725-3,775 Debt and equity offerings Midstream debt and equity financings ,460-1,660 Proceeds from investments and other Total: $2,635 - $2,685 $6,400 - $7,350 $6,900 - $7,900 $15,935 - $17,935 Net Cash Uses ($ in millions) Drilling $1,400 - $1,500 $2,800 - $3,100 $3,500 - $3,800 $7,700 - $8,400 Geologic and geophysical Midstream infrastructure and compression ,300-1,525 Other PP&E Dividends, capitalized interest, etc ,150-1,400 Cash income taxes Total: $2,325 - $2,575 $4,350 - $4,950 $4,900 - $5, $11,575 - $13, Net Cash Change $ $2,050-2,400 $2,000-2,325 $4,360-4,835 $3.5 billion revolving credit facility ($ in millions) Beginning balance, net of cash on hand $1,500 $1,290 ($935) Potential change ($210) ($2,225) ($2,165) Ending balance, net of cash on hand $1,290 ($935) ($3,100) Production (bcfe per day) Proved reserves (3) (tcfe) Proved reserves per fully diluted share (mcfe) YOY % change in proved reserves per FD share 15% 10% 11% Debt to Capitalization 40% 34% 26% Long-term debt, net of cash on hand ($ in millions) (4) $11,870 $9,645 $7,480 Long-term debt per mcfe of proved reserves $0.97 $0.70 $ (1) From Outlook as of 12/7/08 and assumes NYMEX prices of $6.95/mcf and $63.91/bbl in 4Q 08 and $7.00- $8.00/mcf, $70/bbl and $80/bbl in 2009 and 2010, respectively (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 (4) Pro forma for conversion of $765 million of convertible senior notes for 24 million shares in 4Q 08

26 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 60% $ Total 37% $ Total 46% $9.58 Natural Gas Collars (5) % Hedged NYMEX Avg. Floor Price Nymex Avg. Ceiling Price 4Q 2008 Total 14% $7.75 $ Total 38% $7.36 $ Total 3% $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 12/5/08 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 12/7/2008 (3) Includes positions with knockout provisions for 12% of 2009 at knockout prices of $ $6.75 and for 35% of 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 26

27 Summary

28 CHK = Great Value September 30, Pro Forma 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 Proved reserves $ 15,600 $ 19,800 $ 23,900 $ 28,100 $ 32,300 Unproved reserves (2) 5,500 10,900 21,800 32,700 43,700 Value of CHK hedges (3) 3,500 3,300 3,600 2,600 1,600 Value of CNR hedges - - (100) (100) (100) Other assets (4) 4,500 4,500 4,500 4,500 4,500 PXP, BP and STO future drilling cost receivables 4,525 4,525 4,525 4,525 4,525 Less: long-term debt (net of cash equivalents) (10,800) (10,800) (10,800) (10,800) (10,800) Less: preferred stock (when not dilutive) (500) (300) Less net working capital (1,800) (1,800) (1,800) (1,800) (1,800) Shareholder value $ 20,525 $ 30,125 $ 45,625 $ 59,725 $ 73,925 Fully diluted common shares (in millions) (5) NAV per share $ $ $ $ $ Potential % upside (5) 125% 227% 391% 542% 695% Asset value to long-term debt 2.9x 3.8x 5.2x 6.5x 7.8x Leasehold Transaction Implied Values Undrilled Implied Shale Implied Shale NYMEX Strip 12/5/08 Acres Net Leasehold Leasehold Value Oil Gas Plays to CHK Value/Acre ($ in billions) 694 Marcellus Shale 1,200,000 $5,800 $7.0 4Q 2008 $ $ $ $ 6.17 Haynesville Shale 480,000 $15,000 $ $ $ 7.25 Fayetteville Shale 415,000 $12,500 $ $ $ 7.51 Fort Worth Barnett Shale Core & Tier 1 280,000 $17,500 $ $ $ 7.50 All other plays 13,225,000 $1,000 $13.2 Total 15,600,000 $2,402 $ Year Average $ $ 7.07 (1) NYMEX natural gas price scenarios and NYMEX oil price held constant at $ per bbl - Pro forma for recent Marcellus Shale JV with StatoilHydro; $1.25 billion in cash received at closing (2) 55 tcfe of unproved reserves valued from $0.10-$0.80/mcfe (3) As of Outlook issued on 12/7/08 (4) Buildings, drilling rigs, midstream gas assets at net book value and investments at market value (5) Based on common stock price of $15.00 per share Pro forma for conversion of $765 million of convertible senior notes for 24 million shares in 4Q 08 28

29 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, 5-10% in 09 and 10-15% in 10 Sustainability 55 tcfe of proved and risked unproved reserves; >10-year drilling backlog of ~35,500 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 staggered long-term debt maturities; greatly expanded equity base; substantial deleveraging possible through asset monetization program over the next two years Income Pay a $0.30 annual common stock dividend 29 Reflects CHK s Outlook as of 12/7/08 Risk disclosure regarding unproved reserve estimates appears on page 34

30 Appendix

31 Natural Gas Advantages CLEAN: Carbon-light structure represents a key advantage for America s energy ft 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 ~$1.14 per gallon in Oklahoma and if you had a home fueling unit your price would be between $0.80 $0.95 per gallon 31

32 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 32

33 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 33 (1) ISIN #

34 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. 34

35 Forward-Looking Statements This presentation includes include 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 future natural gas and oil reserves, 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. 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 U.S. Securities and Exchange Commission on November 26, These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; unanticipated adverse effects the current financial crisis may have on our business and financial condition; 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; our ability to compete effectively against strong independent natural gas and oil companies and majors; 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; possible 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. 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 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. 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. 35