Filed Pursuant to Rule 433
Registration No. 333-138966
November 27, 2006
The following information supplements the Preliminary Prospectus, dated November 27, 2006, filed pursuant to Rule 433, Registration Statement No. 333-138966 .
Chesapeake
Natural Gas.
Natural Advantages.
€400 Million Senior Notes Offering
November 2006
€400 Million Senior Notes Offering – November 2006
Offering Summary
Issuer: Notes Offered: Use of Proceeds: Form of Offering: Maturity: Guarantees: Ranking Optional Redemption: Change of Control: Listing: Existing Senior Unsecured Notes Ratings: Expected Pricing Date: Joint Bookrunners:
Chesapeake Energy Corporation
€400 million of Senior Unsecured Notes (US $512 million equivalent) (1)
To repay outstanding indebtedness on revolving credit facility and fees and expenses
Registered offering
January 15, 2017
Existing and future domestic restricted subsidiaries
Pari passu with existing and future senior indebtedness
Make-whole call at B + 50 bps 101%
Have applied to list on the Irish Stock Exchange for trading on its Alternative Securities Market
Moody’s: Ba2 (stable) S&P: BB (stable) Fitch: BB (stable)
Friday, December 1, 2006
Barclays Capital Credit Suisse Deutsche Bank Goldman Sachs
(1) Assumes exchange rate of US $1.28/ €1.00
The issuer has filed a registration statement (including a prospectus) with the SEC for the offering to which this communication relates. Before you invest, you should read the prospectus in that registration statement and other documents the issuer has filed with the SEC for more complete information about the issuer and this offering. You may get these documents for free by visiting EDGAR on the SEC Web site at www.sec.gov. Alternatively, the issuer, any underwriter or any dealer participating in the offering will arrange to send you the prospectus if you request it by calling +44 20 7773 9498 or by calling toll-free 1(888)227-2275 ext. 5576.
Chesapeake
Natural Gas.
Natural Advantages. 2
€400 Million Senior Notes Offering – November 2006
Sources and Uses
Sources (1)
Senior Notes due 2017 $512 mm
Total Sources $512 mm
Uses (1)
Repay borrowings on revolving credit facility $503 mm Fees and expenses 9 mm
Total Uses $512 mm
| (1) |
|
Assumes exchange rate of US $1.28/ €1.00 |
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€400 Million Senior Notes Offering – November 2006
CHK Overview
3rd largest independent producer of U.S. natural gas: (trail only APC and DVN), #7 overall (including majors, utilities and pipelines) #1 driller in U.S.: 122 operated rigs, 99 non-operated rigs, collector of 10% of all daily drilling info generated in the U.S.
#1 hedger in industry: 57% of 4Q 2006 production hedged at $9.10/mcfe, 57% of 2007 hedged at $9.61/mcfe and 51% of 2008 hedged at $9.37/mcfe; 2006 realized and locked gains of $1.3 billion Increasing production profile: 1,597 mmcfe/day Q3 ‘06 reported production—22% YOY increase;
1,586 mmcfe/day projected ‘06 production—24% YOY increase; 1,836 mmcfe/day projected ‘07 production
- 16% YOY increase; 2,055 mmcfe/day projected ‘08 production -12% YOY increase
Large proved reserve base: 8.5 tcfe of pro forma proved reserves at 9/30/06, 92% natural gas, 63% proved developed, 13.9 year R/P
A top gas resource play: 16.4 tcfe of risked unproved reserve potential in: i) conventional gas resource, ii) unconventional gas resource, iii) emerging gas resource and iv) Appalachian gas resource plays; >10-year drilling inventory and nearly 25,000 net drilling locations One of the industry’s leading leasehold and seismic positions: 10.5 mm net acres of U.S. onshore leasehold plus 14.7 mm acres of 3-D seismic 2007 estimates: ebitda $4.9 billion; operating cash flow $4.5 billion; net income to common $1.7 billion CHK offers great value to investors: 3.6x operating cash flow, 5.0x ebitda, 9.9x P/E ratio $24.4 billion EV: $16.3 billion equity value, $8.0 billion long-term debt and ($0.1) billion net working capital Top stock price performance: CHK up more than 24x in 13 years as a public company, #2 performer among large-cap E&P companies during that period; #1 since 1/1/1999
Data above incorporates:
CHK’s Outlook and realized and locked gains as of 10/26/06
Pro forma for acquisitions and acreage positions announced 10/26/06
An assumed common stock price of $32.50, NYMEX prices of $8.00/mcf and $56.25/bbl for 2007 and excludes effects of FAS 133 (unrealized hedging gain or loss) Reconciliations of ebitda and operating cash flow (before changes in assets and liabilities) to GAAP measures appear in slide 30 Risk disclosure regarding unproved reserve estimates appears in slide 51
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€400 Million Senior Notes Offering – November 2006
Strong 3Q06 Results
Top-tier production growth
Increased 3Q’06 production to 1.6 bcfe/day; 22% YOY growth; 2% sequential quarterly growth (21st consecutive quarterly increase)
Strong Q3 financial performance $1.9 billion of revenues $1.1 billion of adjusted ebidta(1) $989 million of operating cash flow(1)(2) $373 million of adjusted net income to common(1) ($0.83 per fully diluted common share, up 28% YOY)
Increased proved reserves at 9/30/06 to 8.4 tcfe
12% YTD growth
Replaced production of 426 bcfe with 1,339 bcfe of new proved reserves for a 314% reserve replacement rate Achieved an attractive drilling and proved acquisition costs of $1.89/mcfe(3) Unproved reserves increased to 16.4 tcfe
Remained the most active driller in the U.S. by a wide margin Continued to mitigate risk through gas price and service cost hedges
(1) Refer to the Investor Relations section of our website, www.chkenergy.com, under Financial Reports for reconciliation of this non-GAAP measure to the comparable GAAP measure (2) Before changes in assets and liabilities (3) Excluding tax basis step-up and asset retirement obligation, leasehold and unproved reserve acquisitions and downward natural gas price-related proved reserve revisions
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€400 Million Senior Notes Offering – November 2006
CHK: Biggest Gas Resource Play in the U.S.
Gas-focused Gas-focused Well diversified Well diversified All onshore U.S. All onshore U.S.
Not in the GOM (high and dry) Not in the GOM (high and dry)
Not in the Rockies (fewer hassles, better gas prices) Not in the Rockies (fewer hassles, better gas prices) Not international (lower political risk) Not international (lower political risk)
Anadarko Basin
Barnett and Woodford Shale Plays
Permian Basin
Delaware Basin
Barnett Shale
Woodford Shale
AppalachianBasin
Scale: 1 inch = 275 miles
New Albany Shale
Arkoma Basin
Fayetteville Shale
South Texas
Alabama
Counties with CHK leasehold
Mississippian & Devonian black shales
Thrust Belt
CHK OKC headquarters CHK operated rigs (122)
CNR Charleston headquarters CHK non-operated rigs (99)
CHK/CNR field offices
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€400 Million Senior Notes Offering – November 2006
CHK’s Successful Business Strategy
Following operational failures and oil/gas price collapse in the late 1990s, CHK revamped its business strategy and for the past 8 years has executed a simple and highly effective business strategy:
Balanced growth through acquisitions and the drillbit
Focus on long-lived, low-decline, onshore US gas reserves that have become much more valuable over time
Rediscover the lost art of deep gas exploration through new investments in people, land and seismic in the right areas
Regional consolidation to generate operating scale, maintain low operating and administrative costs and deliver high returns
CHK’s scale in its core areas is a real competitive advantage and has created negotiating power, informational advantages and attracted top industry talent
Concentration on gas
One of the first companies to recognize and capitalize on tightening supply/demand fundamentals and permanent upward shift in gas prices that began in ‘99
A top gas resource play: 10.5 mm net acres, nearly 25,000 net drillsites, most active drilling program in the U.S.
CHK has benefited from substantial first mover advantages and has builtCHK has benefited from substantial first mover advantages and has built a top U.S. natural gas resource base a top U.S. natural gas resource base
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€400 Million Senior Notes Offering – November 2006
CHK’s Continuing Growth
Production(1) (Bcfe)
Oil Gas
800 750 700 650 600 550 500 450 400 350 300 250 200 150 100 50 0
1993 1999 2000 2001 2002 2003 2004 2005 2006E2007E2008E
| 4 |
|
133 134 161
181
268
363
469
579
670
752
53% CAGR
27% CAGR
188x growth over 15 years
73x growth over 14 years
36% CAGR
35% CAGR
Proved Reserves(2) (Bcfe)
Oil Gas
10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0
1993 1999 2000 2001 2002 2003 2004 2005 2006E 2007E
1,206 1,355 137
1,780 2,205
4,902
3,169
7,521
9,000
10,000
Estimated 2006 production is 91% gas Estimated 2006 production is 91% gas 2005 production was up 29% over 2004 levels 2005 production was up 29% over 2004 levels
2006 production is forecast to be up 24% over 2005 levels 2006 production is forecast to be up 24% over 2005 levels 2007 production is forecast to be up 16% over 2006 levels 2007 production is forecast to be up 16% over 2006 levels 2008 production is forecast to be up 12% over 2007 levels 2008 production is forecast to be up 12% over 2007 levels
(1) Based on the mid-point of guidance as of 10/26/06. Estimates of future production are based on current production rates adjusted for expected decline rates, anticipated results from new drilling (2) Projections of future reserves are internally estimated beginning with proved reserves at 9/30/06, pro forma for acquisitions and acreage positions announced 10/26/06
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€400 Million Senior Notes Offering – November 2006
CHK’s Business Strategy
Growth through acquisitions
Acquire, exploit, extend and explore
Growth through the drillbit
Onshore U.S. east of the Rockies
Regional consolidation
Benefit from economies of scale
Gas, gas, gas
Volatility creates opportunities
9
€400 Million Senior Notes Offering – November 2006
Keys To Being A Successful Acquirer
Focus
Know what you want to buy, where you want to buy it and how you want to buy it
Experience
Inexperienced or occasional buyers generally do not succeed. CHK has a consistent approach to acquiring and assimilating acquisitions. CHK is always in the market and has 50 people working full-time on acquisition integration
Operational Skill
Must be able to operate acquired properties more efficiently than sellers. Significant operating scale and attention to detail are the keys to achieving efficiencies
Drillbit Expertise
Must be able to accurately assess, accelerate and deliver upside from PUDs, probables, possibles and exploration opportunities
CHK has executed more acquisition transactions in the past eight CHK has executed more acquisition transactions in the past eight years than any other E&P company – years than any other E&P company –experience helps preventexperience helps prevent mistakes! mistakes!
10
€400 Million Senior Notes Offering – November 2006
CHK’s Acquisitions: First Mover Advantages
Year Major Deals Proved Reserves Acquired (in bcfe) Proved & Unproved Reserves (in bcfe) All-in Costs (1) ($mm) All-in Costs(1) ($/mcfe) CHK Realized Prices ($/mcfe) Net Margin
1998 AnSon, DLB, Hugoton 750 750 $861 $1.15 $1.97 $0.82
1999 Misc. 101 168 $117 $0.70 $2.10 $1.40
2000 Misc. 108 113 $90 $0.80 $3.50 $2.70
2001 Gothic, Sapient, RAM, Apache 648 661 $794 $1.20 $4.56 $3.36
2002 Canaan, Focus, Williams, EnCana 275 276 $381 $1.38 $3.61 $2.23
2003 Oneok, El Paso, Vintage, Oxley, Exxon, Laredo, Union, Kerr-McGee 805 1,051 $1,654 $1.57 $4.79 $3.22
2004 Concho, Permian, Greystone, Bravo, Legend, Tilford Pinson and Hallwood I 1,137 2,043 $3,445 $1.69 $5.23 $3.54
2005 BRG, Laredo II, Pecos, Rubicon, Classic, Hallwood II, Columbia Natural Resources and others Four Sevens, DFW, six private 2,041 4,309 $10,477 $2.43 $6.90 (2) $4.47
2006 Four Sevens, DFW, six private companies and others 568 2,415 $6,040 $2.50 $8.83 $6.33
Totals / Weighted Averages 6,433 11,786 $23,859 $2.02(3) $6.19(3) $4.17
Acquisition margins remain attractive…
(1) Excludes $987 million of deferred taxes in connection with certain corporate acquisitions and acreage and leasehold expenditures; includes future development costs of $11.7 billion to develop the proved and unproved reserves. Disclosure regarding unproved reserves estimates appear in slide 51 (2) Includes realized hedging gains and losses; 2006 includes prices from open NYMEX contract months as of 11/17/06 (3) Weighted averages based on proved and unproved reserves
11
€400 Million Senior Notes Offering – November 2006
Acquisition Margins Remain Attractive
CHK average realized oil and natural gas prices – per mcfe (1) All-in acquisition cost – per mcfe (2) Net margin between cost and realized prices $10.00 $9.00 $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 $1.97 $0.82 $1.15 $2.10
$1.40
$0.70 $3.50
$2.70
| $0.80 |
|
$4.56 $4.79 $3.61 |
$3.22 $3.36 $2.23
| $1.38 |
|
$1.57 $1.20 $5.23 |
$3.54
$1.69 $6.90
$4.47
$2.43 $8.83 $6.33 $2.50
8-year CAGR
20.6% 29.1% 10.2%
1998 1999 2000 2001 2002 2003 2004 2005 2006
Oil and gas price increases have far outpaced acquisition cost Oil and gas price increases have far outpaced acquisition costincreases increases Margins matter, not per mcfe sticker price Margins matter, not per mcfe sticker price
| (1) |
|
Includes realized hedging gains and losses; 2006 includes prices from open NYMEX contract months as of 11/17/06 |
(2) Excludes $987 million of deferred taxes in connection with certain corporate acquisitions and acreage and leasehold expenditures; includes future development costs of $11.7 billion to develop the proved and unproved reserves. Disclosure regarding unproved reserves estimates appear in slide 51.
€400 Million Senior Notes Offering – November 2006
CHK’s Business Strategy
Growth through acquisitions
Acquire, exploit, extend and explore
Growth through the drillbit
Onshore U.S. east of the Rockies
Regional consolidation
Benefit from economies of scale
Gas, gas, gas
Volatility creates opportunities
13
€400 Million Senior Notes Offering – November 2006
Why is CHK the Most Active U.S. Driller?
Most active driller in U.S. by a wide margin
122 operated rigs currently drilling (plus 99 non-operated rigs drilling); ~133 operated rigs by year-end 2006; up to 150 operated rigs in 2007
CHK gathers 10% of all the daily drilling information generated in America This is a distinct competitive advantage 1/4 of rigs drilling to targets > 15,000’; 1/2 between 10-15,000’; 1/4 < than 10,000’
Drill more deep onshore wells than anyone in the industry
Also one of the leading horizontal drillers in the industry
If properly executed, good drilling easily generates the highest returns on capital: 50-100%+ vs. 15-25% on acquisitions However, creating value through the drillbit today is difficult
You had to start getting ready 5 years ago
Quality land, people and seismic are scarce resources
Since 2000, CHK has invested $5.7 billion to build one of the industry’s largest inventories of U.S. leasehold (10.5 mm net acres) and 3-D seismic (14.7 mm acres)
First mover in acquiring the land, people and seismic to support future growth
Amassed > 10-year inventory of nearly 25,000 net drill sites
Only company currently active in all of the major shale plays outside of the Rockies, including: the Ft. Worth Barnett, Arkansas Fayetteville, the West Texas Barnett and Woodford, SE Oklahoma Woodford, and various shale plays in Appalachia and Alabama
CHK is uniquely positioned to transfer and apply technology, informationCHK is uniquely positioned to transfer and apply technology, information and geoscience knowledge base across all operating regions and geoscience knowledge base across all operating regions
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€400 Million Senior Notes Offering – November 2006
Balanced Production Growth
1,700 1,600 1,500 1,400 1,300 1,200 1,100 1,000 900 800 700 600 500 400 300 200 100 0
450 mmcfe/day
1,597 mmcfe/day
2006 Q3 Average Production
507 mmcfe/day acquisition production growth (44% of growth)
640 mmcfe/day drillbit production growth (56% of growth)
208 mmcfe/day drillbit production maintenance
242 mmcfe/day base production
Base as of 4Q’01
Drillbit Production Growth
Drillbit Production Maintenance Acquisition Growth 4Q’01 to 3Q’06
We believe CHK’s operating performance since January 2002 has been the best among the 20 largestWe believe CHK’s operating performance since January 2002 has been the best among the 20 largest E&P companies E&P companies During this time, our production has more than tripled, with over half of this growth coming from theDuring this time, our production has more than tripled, with over half of this growth coming from the drillbit drillbit Through the drillbit only, CHK has created a top 20 U.S. gas producer from scratch in past 4 3/4 Through the drillbit only, CHK has created a top 20 U.S. gas producer from scratch in past 4 3/4years years
4Q’01 1Q’02 2Q’02 3Q’02 4Q’02 1Q’03 2Q’03 3Q’03 4Q’03 1Q’04 2Q’04 3Q’04 4Q’04 1Q’05 2Q’05 3Q’05 4Q’05 1Q’06 2Q’06 3Q’06
Total production has increased
1,147 mmcfe/day
in 19 quarters, or 31% CAGR
21% CAGR through the drillbit
18% initial base decline rate
9% current base decline rate
€400 Million Senior Notes Offering – November 2006
CHK: Tremendous Gas Resource Upside
Positioned for strong sustainable growth Ten-year inventory of nearly 25,000 net drillsites to develop 3.2 tcfe of proved undeveloped reserves and 16.4 tcfe of unproved reserves
Conventional gas resource Unconventional gas resource
Emerging unconventional gas resource Appalachian Basin gas resource
Net Acreage
(10.5 million acres)
| 3.5 |
|
3.1 |
1.3 2.6
Drillsites
(24,800 net drillsites)
3,200
8,700
9,800
3,100
Proved Undeveloped Reserves
(3.2 tcfe)
0.5
| 0.1 |
|
1.0 |
1.6
Unproved Reserves
(16.4 tcfe)
| 1.9 |
|
2.9 |
5.1
6.5
Continue to actively expand all play types through an aggressive land acquisition program utilizing ~1,000 contract land brokers in the field Most recently, CNR acquisition opens up multiple unconventional shale, tight sand and CBM plays in Appalachia
Note: As of 9/30/06, pro forma for acquisitions and acreage positions announced 10/26/06. Disclosure regarding unproved reserve estimates appears in slide 51.
During the past 8 years, CHK has amassed a top U.S. gas resource During the past 8 years, CHK has amassed a top U.S. gas resourceplayplay We are in every important gas resource play in the U.S. east of the Rockies We are in every important gas resource play in the U.S. east of the Rockies
€400 Million Senior Notes Offering – November 2006
CHK Resource Upside Summary
Gas Resource Plays Net Acreage Proved Developed Reserves (Bcfe) Proved Undeveloped Reserves (Bcfe) Risked Unproved Reserves (Bcfe) Risked Unproved as a % of Unrisked Total Proved and Risked Unproved Reserves (Bcfe) Unrisked Unproved Reserves (Bcfe)
Conventional Gas Resource Plays 3,100,000 2,910 945 2,900 15.4% 6,755 18,850
Unconventional Gas Resource Plays 1,300,000 1,421 1,582 6,500 57.8% 9,503 11,250
Fort Worth Barnett Shale 165,000 406 470 3,300 82.5% 4,176 4,000
Sahara 570,000 401 401 2,300 71.9% 3,102 3,200
Ark-La-Tex Tight Gas Sands 270,000 331 349 500 18.7% 1,180 2,675
Granite, Atoka and Cherokee Washes 135,000 265 338 300 27.3% 903 1,100
Other Unconventional Plays 160,000 18 24 100 36.4% 142 275
Emerging Unconventional Gas Resource Plays 2,600,000 69 137 5,100 15.0% 5,306 34,100
Fayetteville Shale 340,000 12 35 2,500 16.1% 2,547 15,500
Deep Haley 235,000 30 74 900 24.3% 1,004 3,700
Delaware Basin Shales 700,000 0 0 1,000 9.8% 1,000 10,250
Woodford Shales 100,000 23 14 400 44.4% 437 900
Deep Bossier 180,000 4 14 200 10.0% 218 2,000
Other Emerging Unconventional Plays 1,045,000 0 0 100 5.7% 100 1,750
Appalachian Basin Gas Resource Plays 3,500,000 901 504 1,900 54.3% 3,305 3,500
Total 10,500,000 5,301 3,168 16,400 24.2% 24,869 67,700
Note: As of 9/30/06, pro forma for acquisitions and acreage positions announced 10/26/06. Disclosure regarding unproved reserve estimates appears in slide 51.
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€400 Million Senior Notes Offering – November 2006
CHK’s Business Strategy
Growth through acquisitions
Acquire, exploit, extend and explore
Growth through the drillbit
Onshore U.S. east of the Rockies
Regional consolidation
Benefit from economies of scale
Gas, gas, gas
Volatility creates opportunities
€400 Million Senior Notes Offering – November 2006
Why Regionally Consolidate?
We believe most E&P companies asset bases are too diversified, too spread out Result is often operational mediocrity – sometimes incoherent corporate strategy and resulting investor unease about the future CHK believes top-tier business success can only be achieved by trying to be better at one thing than everyone else – for CHK, that’s onshore in the southwest U.S. and in the Appalachian Basin Scale brings many benefits:
Negotiating power: CHK demands and receives best prices and best services from service industry
Information advantages: CHK receives > 50% of all drilling information generated in the Mid-Continent. There is tremendous value in this unique and sustainable competitive advantage
Attracting talent: The best geologists, engineers, and landmen want to work where the action is Our strategy is clear, concise and consistent. What we do has worked, is working and should keep working for the foreseeable future
CHK’s CHK’s operating areas are still very fragmented and in the yearsoperating areas are still very fragmented and in the years ahead likely to produce further consolidation opportunities ahead likely to produce further consolidation opportunities
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€400 Million Senior Notes Offering – November 2006
CHK’s Business Strategy
Growth through acquisitions
Acquire, exploit, extend and explore
Growth through the drillbit
Onshore U.S. east of the Rockies
Regional consolidation
Benefit from economies of scale
Gas, gas, gas
Volatility creates opportunities
20
€400 Million Senior Notes Offering – November 2006
Why Has CHK Focused on Gas Since 1998?
Our operating strategy failure in 1997-1998 taught us that:
Significant new reserves of U.S. natural gas would be more difficult to find
Finding costs would accelerate over time
Depletion rates would accelerate over time
Boom in gas fired power plants would cause a natural gas train wreck over time We thought that supply/demand fundamentals would steadily improve
Demand trendline would be up 1-3% per year, supply trendline would be down 0-2% per year
In pricing: higher highs, higher lows – the trend would be our friend
Today, except for excess storage overhang from last winter, supply and demand are in relatively good balance with stabilized U.S. production (through a doubling of the rig count since 2003) and price rationed demand; how long can onshore production growth offset GOM declines; when will rig count begin to retreat (laying the groundwork for higher prices in 2008 and beyond)?
Volatility is high and likely to increase. We love gas price volatility – why?
Weather has played a key role in remarkable recent volatility
Volatility creates opportunity to hedge unusually high prices that generate unusually high returns; helps unlock the option value embedded in long-life reserves
This option value is a key “x” factor enhancing the value of long-lived assets and it comes free with acquisitions
Volatility reduces investment in the industry, which dampens supply LNG is a risk to be monitored
But, our view is that U.S. gas prices will need to approximate BTU parity with world oil prices to attract LNG imports in the 2009 and beyond time frame
Worldwide liquefaction capacity rather than U.S. regas capacity will be the bottleneck
Recent summer storage withdrawals set the stage for even betterRecent summer storage withdrawals set the stage for even better future market dynamics – future market dynamics –decreasing gas available for injection in thedecreasing gas available for injection in the summer may offset future LNG oversupply summer may offset future LNG oversupply
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€400 Million Senior Notes Offering – November 2006
CHK is the 7th Largest U.S. Gas Producer
Production Ranking
Company (C)
Ticker 3Q ‘06 2Q ‘06 3Q ‘05
Daily U.S. Natural Gas Production (A,B)
3Q ‘06 vs. 2Q ‘06 % Change
3Q ‘06 vs. 3Q ‘05 % Change
Reported U.S.
Net Proved Gas Reserves
Proved Gas Reserve Ranking
RP Ratio (D)
Drilling at US Rigs 11/10/2006(E)
| 1. |
|
ConocoPhillips/BR COP 2,443 2,428 2,170 0.6% 12.6% 16,228 1 18.2 44 |
| 2. |
|
BP BP 2,332 2,493 2,456(6.5%)(5.0%) 13,594 3 16.0 23 |
| 3. |
|
Chevron CVX 1,846 1,832 1,676 0.8% 10.1% 4,428 9 6.6 15 |
| 4. |
|
Anadarko (1) APC 1,693 1,090 1,098 55.3% 54.2% 11,132 4 18.0 59 |
| 5. |
|
Devon (2) DVN 1,624 1,493 1,485 8.8% 9.4% 5,164 7 8.7 45 |
| 6. |
|
ExxonMobil XOM 1,588 1,673 1,614(5.1%)(1.6%) 13,692 2 23.6 12 |
| 7. |
|
Chesapeake (3) CHK 1,455 1,427 1,183 2.0% 23.0% 6,901/8,433 5 13.0 122 |
| 8. |
|
XTO (4) XTO 1,213 1,175 1,087 3.2% 11.6% 6,086 6 13.7 57 |
9. EnCana (5) ECA 1,197 1,169 1,099 2.4% 8.9% 3,129 11 7.2 41 10. Shell RD 1,186 1,175 948 0.9% 25.1% 2,680 13 6.2 23 11. Dominion D 996 1,002 896(0.6%) 11.2% 4,856 8 13.4 26 12. EOG (6) EOG 837 776 724 7.9% 15.6% 2,948 12 9.6 58 13. Williams WMB 780 738 623 5.7% 25.3% 3,382 10 11.9 28 14. Apache (7) APA 719 638 586 12.7% 22.7% 1,711 16 6.5 20 15. El Paso EP 646 619 576 4.4% 12.1% 1,830 15 7.8 13 16. Occidental OXY 597 601 564(0.7%) 5.9% 2,338 14 10.7 15 17. Newfield (8) NFX 557 527 509 5.5% 9.4% 1,440 19 7.1 25 18. Marathon MRO 522 524 562(0.3%)(7.1%) 1,209 20 6.3 13 19. Noble (9) NBL 430 493 414(12.8%) 3.9% 1,641 17 10.5 12 20. Questar STR 367 344 315 6.8% 16.5% 1,480 18 11.0 13 Totals / Average 23,028 22,217 20,584 3.7% 11.9% 105,869 11.3 664
The top 20 gas producers (with their royalty owners @ 20%) account The top 20 gas producers (with their royalty owners @ 20%) account for 50% of U.S. gas production, but only 40% of drilling activity for 50% of U.S. gas production, but only 40% of drilling activity
(A) Based on company reports (B) In mmcf per day
(C) Independents in green, majors in black, pipelines in red
(D) Based on annualized 2Q06 production and 2005 natural gas reserves (E) Source: Smith International Survey (operated rig count)
(F) CHK’s reported U.S. net proved natural gas reserves in 2005 were 6,901 Bcf. Reserves of 8,433 as of 9/30/06.
(G) APC’s reported U.S. net proved natural gas reserves in 2005 were 6,578 Bcf. Reserves of 11,132 are pro forma for the Kerr McGee and Western Gas acquisitions.
€400 Million Senior Notes Offering – November 2006
Financial Information
23
€400 Million Senior Notes Offering – November 2006
Expanding Cash Margins andSteady Debt Levels Per Mcfe
Net cash margin Preferred dividends Interest expense (1) G&A (2) Production tax Production expense
Long term debt/mcfe of proved reserves $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
Sept 2006 YTD Averages (per mcfe)
Realized price $8.77
Sept 2006 YTD net cash margin: $6.77
Preferred dividends: $0.15 Interest expense: $0.52 G&A: $0.18 Production tax: $0.30 Production expense: $0.85
Total cash costs: $2.00 $0.82 $2.14 $3.17 $2.14 $3.28 $3.73 $5.12 $6.77
1999
B3/B
2000
B2/B
Sr. Unsecured Rating
2001
B1/B+
2002
B1/B+
2003
Ba3/BB-
2004
Ba3/BB-
2005
Ba2/BB
YTD 2006
Ba2/BB
$/ m cfe
CHK has successfully managed controllable costs and enjoyed rapidly expanding CHK has successfully managed controllable costs and enjoyed rapidly expanding margins from rising price realizations margins from rising price realizations Long Term Debt per mcfe of proved reserves has remained relatively flat, while the Long Term Debt per mcfe of proved reserves has remained relatively flat, while the value of reserves has expanded substantially value of reserves has expanded substantially
| (1) |
|
Excludes unrealized gains/losses on interest rate derivatives (2) Excludes non-cash stock based compensation |
24
€400 Million Senior Notes Offering – November 2006
Greatly Strengthened Balance Sheet
Preferred stock
Common stock, retained earnings & other LT debt / book capitalization $12 $11 $10 $9 $8 $7 $6 $5 $4 $3 $2 $1 $0
($ 1)
($ 2)
140% 130% 120% 110% 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0%
$billions
Sr. Unsecured Rating
1999
B3/B
2000
B2/B
2001
B1/B+
2002
B1/B+
2003
Ba3/BB-
2004
Ba3/BB-
2005
Ba2/BB
Q306
Ba2/BB
Strong earnings growth and balanced external funding of acquisitions has greatly Strong earnings growth and balanced external funding of acquisitions has greatly improved CHK’s balance sheet and resulted in multiple rating agency upgrades improved CHK’s balance sheet and resulted in multiple rating agency upgrades
25
€400 Million Senior Notes Offering – November 2006
Balanced Funding of Acquisitions $6,000 $5,000 $4,000 $3,000 $2,000 $1,000 $0
2001 2002 2003 2004 2005 3Q 2006(1) $6,000 $5,000 $4,000 $3,000 $2,000 $1,000 $0
C ommo n St ock Issued Senior N o t es Issued
Pref erred St ock Isssued
To t al Pro ved & U npro ved A cquisit io ns (2)
Cumulative External Financing Mix 2001 to Date
Common Stock & Converted Preferred Stock 31.1%
Senior Notes 52.5%
Outstanding Preferred Stock 16.4%
Chesapeake’s typical approach is to finance acquisitions above the company’sChesapeake’s typical approach is to finance acquisitions above the company’s excess cash flow with a relatively equal balance of debt and equity excess cash flow with a relatively equal balance of debt and equity
(1) Pro Forma for acquisitions and acreage positions announced 10/26/06 and the pending senior notes offering (2) Acquisition cost is of proved and unproved reserves. Excludes acreage and lease acquisition expenditures.
$in millions
26
€400 Million Senior Notes Offering – November 2006
Capitalization Table
As of September 30, 2006 ($in 000’s)
Historical Pro Forma(1)
Cash and Cash Equivalents $716 $ 716
Revolver $1,464,000 $960,570 7.5% Senior Notes due 2013 363,823 363,823 7.625% Senior Notes due 2013 500,000 500,000 7.0% Senior Notes due 2014 300,000 300,000 7.5% Senior Notes due 2014 300,000 300,000 7.75% Senior Notes due 2015 300,408 300,408 6.375% Senior Notes due 2015 600,000 600,000 6.625% Senior Notes due 2016 600,000 600,000 6.875% Senior Notes due 2016 670,437 670,437
[ ]% Senior Notes due 2017 (2)—512,000 6.500% Senior Notes due 2017 1,100,000 1,100,000 6.250% Senior Notes due 2018 600,000 600,000 6.875% Senior Notes due 2020 500,000 500,000 2.75% Convertible Senior Notes due 2035 (first put 2015) 690,000 690,000 Hedging effect from interest rate swaps(23,621)(23,621) Discount on Senior Notes(103,939)(103,939)
Total Debt 7,861,108 7,869,678 44%
5.0% Preferred Stock (series 2003) 3,863 3,863 4.125% Preferred Stock 3,065 3,065 5.0% Preferred Stock (series 2005) 460,000 460,000 4.5% Preferred Stock 345,000 345,000 5.0% Preferred Stock (series 2005B) 575,000 575,000 6.25% Mandatory Convertible Preferred Stock 575,000 575,000 Other Equity 8,230,892 8,230,892
Total Shareholder’s Equity 10,192,820 10,192,820 56% Total Book Capitalization $18,053,928 $18,062,498 100%
| (1) |
|
Pro forma for pending senior notes offering (2) Assumes exchange rate of US $1.28/ €1.00 |
27
€400 Million Senior Notes Offering – November 2006
Senior Note Maturity Schedule @ 9/30/06
Total Senior Notes: $6.5 billion Average Rate: 6.4% Average Maturity: 9.5 years $1,700 $1,600 $1,500 $1,400 $1,300 $1,200 $1,100 $1,000 $900 $800 $700 $600 $500 $400 $300 $200 $100 $0 $1,590(1) $1,612(2)
$1,270 $864
$600 $600 $500
‘06 ‘07 ‘08 ‘09 ‘10 ‘11 ‘12 ‘13 ‘14 ‘15 ‘16 ‘17 ‘18 ‘20
2.75%
7.5% 7.5% 6.375% 6.625% [ ]%
Rate: 7.625% 7.0% 7.75% 6.875% 6.5% 6.25% 6.875%
Staggered long term debt maturity structure with no senior notes Staggered long term debt maturity structure with no senior notesdue fordue for seven years; cash flow ofseven years; cash flow of$$25-35 billion possible before first payment 25-35 billion possible before first payment
| (1) |
|
Recognizes earliest investor put option as maturity |
| (2) |
|
Pro forma for pending senior note offering; assumes exchange rate of US $1.28/ €1.00 |
28
€400 Million Senior Notes Offering – November 2006
2006 Projections @ Various Gas Prices
(as of 10/26/06 and assumes approximately the mid-point of company guidance for each item)
($in millions; gas price at various NYMEX prices; oil at $65.23 NYMEX)
@$7.00 @$7.50 @$8.00 @$8.50 @$9.00 @$9.50 O/G revenue (unhedged) @ 579 bcfe (1) $3,747 $3,790 $3,832 $3,874 $3,916 $3,959 Hedging effect (2) 1,343 1,315 1,287 1,260 1,232 1,204 Marketing and other (@ $0.16/mcfe) 93 93 93 93 93 93 Production taxes (@ 6.0%)(194)(197)(199) (202)(204) (207) LOE (@ $0.88/mcfe)(507)(507)(507) (507)(507) (507) G&A (@ $0.25/mcfe)(3)(142)(142)(142) (142)(142) (142) Ebitda 4,340 4,352 4,364 4,376 4,388 4,400 Interest ($0.56/mcfe)(324)(324)(324) (324)(324) (324) Cash flow (2)(3)(4) 4,016 4,028 4,040 4,052 4,064 4,076 Oil and gas depreciation (@ $2.33/mcfe)(1,346)(1,346)(1,346) (1,346)(1,346) (1,346) Depreciation of other assets (@ $0.20/mcfe)(116)(116)(116) (116)(116) (116) Income taxes (38% rate, 95% deferred)(971)(975)(980) (984)(989) (993) Adj. net income to common(1) $1,583 $1,591 $1,598 $1,606 $1,613 $1,621 Adj. net income to common per fully diluted share $3.45 $3.47 $3.48 $3.50 $3.51 $3.53 Net debt/ebitda(5) 1.8x 1.8x 1.8x 1.8x 1.8x 1.8x Debt to book capitalization ratio 43% 43% 43% 43% 43% 43% Ebitda/fixed charges (including pfd. dividends)(6) 7.7x 7.8x 7.8x 7.8x 7.8x 7.8x MEV/operating cash flow(7) (9) 4.1x 4.0x 4.0x 4.0x 4.0x 4.0x EV/ebitda(8) (9) 5.6x 5.6x 5.6x 5.6x 5.6x 5.5x PE ratio(9) 9.4x 9.4x 9.3x 9.3x 9.3x 9.2x
NOTE: Pro forma for acquisitions and acreage positions announced 10/26/06 (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 ($561 mm) = interest of $458 million plus preferred dividends of $103 million (7) MEV (Market Equity Value) = $16.3 billion ($32.50/share x 501 mm fully diluted shares)
(8) EV (Enterprise Value) = $24.4 billion (Market Equity Value, plus $8.0 billion in long-term debt, and $0.1 billion working capital deficit) (9) Assuming a common stock price of $32.50/share
29
€400 Million Senior Notes Offering – November 2006
2007 Projections @ Various Gas Prices
(as of 10/26/06 and assumes approximately the mid-point of company guidance for each item)
($in millions; gas price at various NYMEX prices; oil at $56.25 NYMEX)
@$7.00 @$7.50 @$8.00 @$8.50 @$9.00 @$9.50 O/G revenue (unhedged) @ 670 bcfe (1) $4,343 $4,622 $4,900 $5,178 $5,457 $5,736 Hedging effect (2) 1,375 1,204 1,034 864 693 523 Marketing and other (@ $0.18/mcfe) 121 121 121 121 121 121 Production taxes (@ 6.0%)(261)(277)(294) (311)(327) (344) LOE (@ $0.95/mcfe)(637)(637)(637) (637)(637) (637) G&A (@ $0.32/mcfe)(3)(211)(211)(211) (211)(211) (211) Ebitda 4,730 4,822 4,913 5,004 5,096 5,188 Interest (@ $0.63/mcfe)(419)(419)(419) (419)(419) (419) Cash flow (2)(3)(4) 4,311 4,403 4,494 4,585 4,677 4,769 Oil and gas depreciation (@ $2.45/mcfe)(1,642)(1,642)(1,642) (1,642)(1,642) (1,642) Depreciation of other assets (@ $0.26/mcfe) (174)(174)(174) (174)(174) (174) Income taxes (38% rate, 95% deferred)(948)(983)(1,018) (1,052)(1,087) (1,122) Net income to common(1) $1,547 $1,604 $1,660 $1,717 $1,774 $1,831 Net income to common per fully diluted share $3.06 $3.18 $3.29 $3.40 $3.51 $3.63 Net debt/ebitda(5) 1.7x 1.7x 1.6x 1.6x 1.6x 1.5x Debt to book capitalization ratio 40% 40% 40% 40% 40% 39% Ebitda/fixed charges (including pfd. dividends)(6) 8.4x 8.6x 8.8x 8.9x 9.1x 9.2x MEV/operating cash flow(7) (9) 3.8x 3.7x 3.6x 3.6x 3.5x 3.4x EV/ebitda(8) (9) 5.2x 5.1x 5.0x 4.9x 4.8x 4.7x PE ratio(9) 10.6x 10.2x 9.9x 9.6x 9.3x 9.0x
NOTE: Pro forma for acquisitions and acreage positions announced 10/26/06 (1) Before effects of FAS 133 (unrealized hedging gain or loss) (2) Includes the non-cash effect of CNR hedges and hedges lifted in October 2006 (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 ($561 mm) = interest of $458 million plus preferred dividends of $103 million (7) MEV (Market Equity Value) = $16.3 billion ($32.50/share x 501 mm fully diluted shares)
(8) EV (Enterprise Value) = $24.4 billion (Market Equity Value, plus $8.0 billion in long-term debt, and $0.1 billion working capital deficit) (9) Assuming a common stock price of $32.50/share
30
€400 Million Senior Notes Offering – November 2006
2008 Projections @ Various Gas Prices
(as of 10/26/06 and assumes approximately the mid-point of company guidance for each item)
($in millions; gas price at various NYMEX prices; oil at $56.25 NYMEX)
@$7.00 @$7.50 @$8.00 @$8.50 @$9.00 @$9.50 O/G revenue (unhedged) @ 752 bcfe (1) $4,899 $5,217 $5,535 $5,853 $6,171 $6,489 Hedging effect (2) 1,011 838 665 492 319 146 Marketing and other (@ $0.18/mcfe) 135 135 135 135 135 135 Production taxes (@ 6.0%)(294)(313)(332) (351)(370) (389) LOE (@ $0.95/mcfe)(714)(714)(714) (714)(714) (714) G&A (@ $0.34/mcfe)(3)(252)(252)(252) (252)(252) (252) Ebitda 4,785 4,911 5,037 5,163 5,289 5,415 Interest (@ $0.63/mcfe)(470)(470)(470) (470)(470) (470) Cash flow (2)(3)(4) 4,315 4,441 4,567 4,693 4,819 4,945 Oil and gas depreciation (@ $2.45/mcfe)(1,842)(1,842)(1,842) (1,842)(1,842) (1,842) Depreciation of other assets (@ $0.30/mcfe) (226)(226)(226) (226)(226) (226) Income taxes (38% rate, 95% deferred)(854)(902)(950) (998)(1,045) (1,093) Net income to common(1) $1,393 $1,471 $1,549 $1,627 $1,706 $1,784 Net income to common per fully diluted share $2.76 $2.91 $3.07 $3.22 $3.38 $3.53 Net debt/ebitda(5) 1.7x 1.6x 1.6x 1.5x 1.5x 1.5x Debt to book capitalization ratio 37% 37% 37% 37% 37% 36% Ebitda/fixed charges (including pfd. dividends)(6) 8.5x 8.8x 9.0x 9.2x 9.4x 9.7x MEV/operating cash flow(7) (9) 3.8x 3.7x 3.6x 3.5x 3.4x 3.3x EV/ebitda(8) (9) 5.1x 5.0x 4.8x 4.7x 4.6x 4.5x PE ratio(9) 11.8x 11.2x 10.6x 10.1x 9.6x 9.2x
NOTE: Pro forma for acquisitions and acreage positions announced 10/26/06 (1) Before effects of FAS 133 (unrealized hedging gain or loss) (2) Includes the non-cash effect of CNR hedges and hedges lifted in 2006 (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 ($561 mm) = interest of $458 million plus preferred dividends of $103 million (7) MEV (Market Equity Value) = $16.3 billion ($32.50/share x 501 mm fully diluted shares)
(8) EV (Enterprise Value) = $24.4 billion (Market Equity Value, plus $8.0 billion in long-term debt, and $0.1 billion working capital deficit) (9) Assuming a common stock price of $32.50/share
31
€400 Million Senior Notes Offering – November 2006
Substantial Hedging Position Reduces Risk, Locks in Value
(as of 10/26/06 and assumes approximately the mid-point of company guidance for each item)
CHK’s open oil and gas hedge positions for 2006, 2007 and 2008 are detailed below(1):
Natural Gas Q4’ 06% Hedged 57% NYMEX Average Price $9.10
2007 57% $9.61
2008 51% $9.37
Natural Gas Lifted Gains Total Gains (millions) Gains/mcf of Total Gas Production
Q4’ 06 $215 $1.54
2007 $290 $0.47
2008 $31 $0.04
Oil% Hedged NYMEX Average Price
Q4’ 06 88% $65.64
2007 72% $71.42
2008 60% $71.45
NYMEX Strip Prices @ 11/17/06 Oil Gas Q4 ‘06 $59.02 $6.51 2007 $63.80 $8.42 2008 $67.65 $8.46 2009 $67.59 $8.05 2010 $66.59 $7.64 Q4’06–’10 avg. $64.93 $7.82
Realized hedging gains 2001-2005:($0.4 billion) Realized hedging gains to date in 2006: $1.3 billion(2) Total: $0.9 billon(2)
(1) Excludes minor amounts of collars, call options and includes locked positions and includes CNR derivative liabilities assumed
Since 2001, CHK’s hedging program has greatly reduced acquisitionSince 2001, CHK’s hedging program has greatly reduced acquisition and financial risks and made investing for the future easier and and financial risks and made investing for the future easier andsafer safer
| (2) |
|
As of 10/26/06; includes gains of $540 million from lifted hedges |
32
€400 Million Senior Notes Offering – November 2006
CHK Has Also Hedged Service Costs
HOW?
Negotiating power through large operating scale
#1 customer of most onshore drilling service providers
We demand and receive best pricing, best equipment, best people
Direct rig ownership: creates acquisition ramp-up advantages; less turnover and loyalty to operator, not contractor; provides operational flexibility
Wholly-owned Nomac Drilling subsidiary increasing its rig fleet from 60 rigs now (including Martex and private Appalachia Basin company) to 82 rigs by mid-year 2007
Estimated current value $200+ mm over CHK investment of ~$500 mm Rig investments:
Invested $24 mm since mid 2005 for a 45% interest in privately-held DHS Drilling Company that has 16 rigs operating
Invested $45 mm since late 2005 and own a 49% interest in privately-held Mountain Drilling Company that owns 6 rigs and has 4 rigs ordered; urban drilling specialist that is perfect for the Fort Worth Barnett Shale Third-party rigs: Sponsored the construction of 20 rigs through various drilling contracts with third party rig builders and operators; rates well below current market levels
CHK’s $500 mm of rig investments have appreciated $200 mm and have or CHK’s $500 mm of rig investments have appreciated $200 mm and have or will increase the U.S. rig fleet by 75 rigs, or 4%, from 2004 to 2006 will increase the U.S. rig fleet by 75 rigs, or 4%, from 2004 to 2006 Note: On the other hand, no one can increase U.S. gas production capacity by Note: On the other hand, no one can increase U.S. gas production capacity by 4% in 2 years, or ever… 4% in 2 years, or ever…
33
€400 Million Senior Notes Offering – November 2006
Summary
34
€400 Million Senior Notes Offering – November 2006
CHK’s NAV Exceeds Current Stock Price
(CHK internal estimates)
As of September 30, 2006 – Pro forma
NAV @ various gas prices(1)
($in millions, except per share data) PV 10 @$6.50 PV 10 @$7.00 PV 10 @$7.50 PV 10 @$8.00 PV 10 @$8.50 PV 10 @$9.00 PV 10 @$9.50
Proved reserves $17,086 $18,661 $20,233 $21,900 $23,565 $25,235 $ 26,889
Unproved reserves (2) 6,560 8,200 9,840 11,480 13,120 14,760 16,400
Value of CHK hedges 3,033 2,643 2,254 1,865 1,476 1,086 697
Value of CNR hedges(182)(238)(294)(350)(405)(461)(517)
Other assets (3) 2,189 2,189 2,189 2,189 2,189 2,189 2,189
Less: long-term debt(7,997)(7,997)(7,997)(7,997)(7,997)(7,997)(7,997)
Less: preferred stock (when not dilutive) (345)————
Less: net working capital(1,108)(1,108)(1,108)(1,108)(1,108)(1,108)(1,108)
Shareholder value $19,236 $22,350 $25,117 $27,979 $30,840 $33,704 $ 36,553
Fully diluted common shares 493 501 501 501 501 501 501
NAV per share $39.02 $44.61 $50.13 $55.85 $61.56 $67.27 $ 72.96
Potential % upside (4) 20% 37% 54% 72% 89% 107% 124%
Asset value to long-term debt 3.6x 3.9x 4.3x 4.6x 5.0x 5.4x 5.7x
NYMEX Strip Prices @ 11/17/06 Oil Gas Q4 ‘06 $59.02 $6.51 2007 $63.80 $8.42 2008 $67.65 $8.46 2009 $67.59 $8.05 2010 $66.59 $7.64 Q4’06–’10 avg. $64.93 $7.82
(1) NYMEX gas price changes and NYMEX oil price held constant at $62.82 per bbl. Reserves at 9/30/06 pro forma for acquisition and acreage positions announced 10/26/06 (2) 16.4 tcfe of unproved reserves valued from $0.40—$1.00/mcfe (3) Buildings, drilling rigs, pro forma midstream gas assets and investments at market value (4) Based on common stock price of $32.50 per share
35
€400 Million Senior Notes Offering – November 2006
Creating More NAV Everyday
In addition to potential acquisitions in ‘07, CHK expects to:
Invest $4.1 billion through the drillbit (1);
Find an estimated 1.8 tcfe @ $2.25/mcfe through the drillbit;
Produce an estimated 670 bcfe;
Replace 670 bcfe of proved reserves and add 1.1 tcfe of proved reserves (newly drilled reserves could be sold for at least @ $3.50/mcfe $4.0 billion of value); and
Generate approximately $200 mm of cash flow above drilling capex (after
$200 mm of common and preferred dividend payments) to invest in other assets, leasehold or acquisitions
Based on these assumptions, CHK could create $4.2 billion of NAV in 2007, or $8.25 per diluted common share, through the everyday execution of our business model – this represents 25% NAV growth in just one year and without any help from 1) accretive acquisitions, 2) additional hedging opportunities or, 3) equity multiple expansion through ongoing de-leveraging
| (1) |
|
Does not include leasehold, seismic and acquisition expenditures |
Note: These expectations for 2007 assume the successful completion of the company’s current business plan and current market conditions and also assumes average NYMEX natural gas prices of $8.00/mcf. None of these assumptions is assured. Actual results will be dependent on our drilling and acquisition success, oil and gas markets and the accuracy of production and reserves estimates.
36
€400 Million Senior Notes Offering – November 2006
Why Own CHK ?
Gas Focus: purest play in U.S. natural gas
Hedging: successful track record of locking in margins and acquisition returns during past 5 years Growth: 21 consecutive quarters of organic production growth vs. industry’s multi-year decline; 35% total production growth in ‘04, 29% in ‘05, 24% in ‘06, and 16% in ‘07, and 12% in ‘08 Sustainability: 24.8 tcfe of proved and unproved reserves; > 10-year drilling backlog of nearly 25,000 net drillsites across multiple gas resource plays Low Risk: uniquely focused business strategy; well-diversified, all-onshore U.S. asset-base; mitigating exposure to oil field service cost inflation through rig investments Balance Sheet: balanced structure; long-term assets financed with long-term debt maturities; greatly expanded equity base Conservative Acquisition Financing: track record of utilizing half debt and half equity to finance acquisitions Strong Credit Profile: steadily improving credit ratings; multiple credit metrics comparable to investment-grade peers Security: strong asset value to debt coverage; substantial cash flow generation capabilities Commitment: Sizeable insider ownership
Note: Disclosure regarding unproved reserve estimates appears in slide 51
CHK = Value, Growth and Opportunity = and
37
€400 Million Senior Notes Offering – November 2006
Appendix
38
€400 Million Senior Notes Offering – November 2006
Conventional Gas Resource Plays
Much of the Mid-Continent, Permian, Gulf Coast, S. Texas and other areas; At least 15 different plays –four highlighted below:
South Texas (Zapata County): 140,000 net acres; CHK 3rd largest producer in the #1 gas producing county in Texas Mountain Front (primarily Morrow & Springer formations in western OK): >130,000 net acres; prolific play initiated by CHK 3-D seismic and leasehold Southern Oklahoma (Cement, Bray, Golden, Trend): >375,000 net acres; three of Oklahoma’s biggest fields; CHK birthplace; new and old plays overlap Permian Basin (W. TX & S.E. NM):
450,000 net acres; 3-D driven exploration at depths ranging from 11,000-15,000’; primarily Atoka horizon
Permian Basin
Zapata County
Texas Gulf Coast
Anadarko Basin Shelf
Deep Anadarko Springer
Arkoma Basin
Conventional Gas Resource Plays 3Q06 Total Net Acreage Estimated Drilling Density (Acres) Assumed Risk Factor Risked Net Undrilled Wells Est. Avg. Reserves Per Well (Gr Bcfe) 3Q06 Booked PUD (Net Bcfe) 3Q06 Risked Net Unproved Reserves (Bcfe) Estimated Average Well Cost (Gr $000) Assumed Royalty Rate Finding Cost/Well ($/Mcfe) Current Op. Rig Count Planned YE 2006 Op. Rig Count October ‘06 Production Rate (Mmcfe/d)
South Texas 140,000 80 75% 350 1.8 169 300 $2,800 24% $2.11 8 8 150
Mountain Front 130,000 320 70% 80 4.0 58 200 $8,000 22% $2.56 3 4 105
Southern Oklahoma 375,000 120 75% 600 2.2 239 800 $3,500 22% $2.04 8 9 154
Other Conventional Plays 2,455,000 2,170 479 1,600 20 19
Sub-total Conventional 3,100,000 3,200 945 2,900 39 40
Note: Pro forma for acquisitions and acreage positions announced 10/26/06. Disclosure regarding unproved reserve estimates appears in slide 51.
CHK built a highly profitable conventional gas resource base in a low gasCHK built a highly profitable conventional gas resource base in a low gas price environment that is now delivering outstanding rates of return price environment that is now delivering outstanding rates of return
39
€400 Million Senior Notes Offering – November 2006
Unconventional Gas Resource Plays
Ft. Worth Barnett Shale (N. TX):
– Established a top-3 position in less than 2 years
– Now have 165,000 net acres primarily in Johnson, Tarrant and Dallas counties (150,000 net acres in the Tier 1 area)
– Four Sevens/Sinclair and Dale Resources, et al acquisition and DFW Airport lease further enhance CHK’s strong position
– Industry-leading initial horizontal well production to date – 2,100 potential net wells at 2.45 bcfe/well on 60 acre spacing
– 17-rig program now increasing to 30-35 rigs in 2007 Sahara (primarily Mississippi, Chester, Hunton formation in NW OK): 570,000 net acres; foundational asset; over 10-year drilling inventory; 640 acre spacing in 1998, now moving down to 40’s –16 wells per section possible Ark-La-Tex Tight Gas Sands (primarily Travis Peak, Cotton Valley, Petit & Bossier formations): 270,000 net acres; CHK rapidly becoming a player in prolific Ark-La-Tex region Granite, Cherokee/Atoka Washes (West OK/TX Panhandle):
135,000 net acres; overlooked formations from low gas price days in Anadarko Basin Hartshorne Coal (Oklahoma Arkoma): 150,000 net acres; CHK has drilled over 300 CBM wells since 2000
Sahara
Granite, Cherokee/ Atoka Washes
Hartshorne Coal
Ark-LaTex Tight Sands
Barnett Shale
Unconventional Gas Resource Plays 3Q06 Total Net Acreage Estimated Drilling Density (Acres) Assumed Risk Factor Risked Net Undrilled Wells Est. Avg. Reserves Per Well (Gr Bcfe) 3Q06 Booked PUD (Net Bcfe) 3Q06 Risked Net Unproved Reserves (Bcfe) Estimated Average Well Cost (Gr $000) Assumed Royalty Rate Finding Cost/Well ($/Mcfe) Current Op. Rig Count Planned YE 2006 Op. Rig Count October ‘06 Production Rate (Mmcfe/d)
Fort Worth Barnett Shale 165,000 60 15% 2,100 2.4 470 3,300 $2,700 23% $1.50 17 24 168
Sahara 570,000 64 25% 5,600 0.6 401 2,300 $900 19% $1.85 15 15 145
Ark-La-Tex Tight Gas Sands 270,000 60 70% 1,100 1.0 349 500 $1,600 20% $2.00 13 13 100
Granite, Atoka and Cherokee Washes 135,000 80 50% 650 1.4 338 300 $2,800 21% $2.53 8 9 115
Other Unconventional Plays 160,000 250 24 100—1
Sub-total Unconventional 1,300,000 9,700 1,582 6,500 53 62
Note: Pro forma for acquisitions and acreage positions announced 10/26/06. Disclosure regarding unproved reserve estimates appears in slide 51.
CHK was early to the realization that repeatability and sustainability of drillingCHK was early to the realization that repeatability and sustainability of drilling success was the best avenue to predictable and attractive value creation success was the best avenue to predictable and attractive value creation
40
€400 Million Senior Notes Offering – November 2006
Fort Worth Barnett Shale
CHK Leasehold City of Ft. Worth
Active Rigs
CHK Operated
Path of Stratigraphic Profile Map
DFW Airport
Net Production vs. Operated Rig Count
150 130 110 90 70 50 30 10
Net Production Operated Rig Count
De c-03
Ma r -
04 Ju n-
04
Se p-
04
De c-04
Mar—05 Jun- 05
Sep- 05
Dec-05
Mar—06 Jun- 06 Sep—06
Dec-06
Expected Economics Sensitivity Analysis
Base well cost + 15%
Base well cost of $2.7 MM/well Base well cost—15%
220% 200% 180% 160% 140% 120% 100% 80% 60% 40% 20% 0% $6.00 $7.00 $8.00 $9.00 $10.00 Average NYMEX Natural Gas Prices
41
Net Daily MMCFE
30 25 20 15 10 5 0
Operated Rigs
Unlevered IRR %
PARKEP
HOOD
TARRANT
DALLAS
JOHNSON
ELLIS
HILL
Strategic Profile
A BOSQUE JOHNSON BASALATOKA MARBLE FALLS BARNETT SHALE FORESTBERG LIME CIOLA ELLENBURGER
€400 Million Senior Notes Offering – November 2006
Sahara
Acreage Position
Path of Stratigraphic Profile Map
SW
Active Rigs CHK Operated
Net Production vs. Operated Rig Count
Net Production Operated Rig Count
150 140 130 120 110 100 90 80
Dec-03
Mar-04
Jun-04
Sep-04
Dec-04
Mar-05
Jun-05
Sep-05
Dec-05
Mar-06
Jun-06
Sep-06
Dec-06
18 16 14 12 10 8 6 4 2 0
Net Daily MMCF
Stratigraphic Profile
8675’—7672’—7155’ -
Area Cedardale 24N-18W Area Area Ridge Waynoka Dixie Area Ranch Area Walker
Expected Economics Sensitivity Analysis
Base well cost + 15%
Base well cost of $900,000/well Base well cost—15%
Operated Rigs Unlevered IRR %
140% 120% 100% 80% 60% 40% 20% 0%
Average gross reserves of 0.6 bcfe/well $6.00 $7.00 $8.00 $9.00 $10.00 Average NYMEX Natural Gas Prices
42
€400 Million Senior Notes Offering – November 2006
Emerging Unconventional Gas Resource Plays
Fayetteville Shale SE OK Woodford Shale
Deep Haley
Deep Bossier Delaware Basin Shales
Fayetteville Shale (Arkansas):
Largest leasehold owner in the play
CHK now believes at least 340,000 of its 1.0 million net acres will be commercially productive
If so, ~2,100 net potential drilling locations to develop 1.4 bcfe/well (working to improve recoveries further); 2-rig program now—up to 7 rigs by year-end 2006
Hope to improve costs through engineering and operational breakthroughs
Deep Haley (primarily Strawn, Atoka, Morrow formations in West Texas): 2nd largest leasehold owner in the play; 235,000 net acres; Permian Basin deep over-pressured gas play in Loving County, TX with APC as a competitor/partner; 8-rig program now and year-end 2006; Delaware Basin Shales (primarily Barnett & Woodford formations in West Texas):
Largest leasehold owner in the play
Recently acquired 700,000 net acres in Reeves, Brewster, Pecos and Culberson Counties in multiple transactions with public and private companies
Shales much thicker than in Ft. Worth Barnett, Arkansas or SE OK; also higher gas-in-place estimates (2-4x higher)
However, it is approximately twice as deep; well costs will be higher and recovery factors are currently unclear
Now have 3 producing vertical wells, 4 wells awaiting completion and 2 wells drilling SE OK Woodford Shale (Oklahoma Arkoma Basin): 3rd largest leasehold owner in play; 100,000 net acres; age equivalent to Fayetteville; have operated one successful vertical and one successful horizontal well Deep Bossier (East Texas & Northern Louisiana): One of the top three leasehold owners in the play; 180,000 net acres; position in the play through Gastar and CHK leasing efforts; now drilling first operated well;
Emerging Unconventional Gas Resource Plays 3Q06 Total Net Acreage Estimated Drilling Density (Acres) Assumed Risk Factor Risked Net Undrilled Wells Est. Avg. Reserves Per Well (Gr Bcfe) 3Q06 Booked PUD (Net Bcfe) 3Q06 Risked Net Unproved Reserves (Bcfe) Estimated Average Well Cost (Gr $000) Assumed Royalty Rate Finding Cost/Well ($/Mcfe) Current Op. Rig Count Planned YE 2006 Op. Rig Count October ‘06 Production Rate (Mmcfe/d)
Fayetteville Shale (Core) 340,000 80 50% 2,100 1.4 35 2,500 $2,500 15% $2.10 2 7 7
Deep Haley 235,000 320 75% 180 7.0 74 900 $10,500 25% $2.00 8 8 26
Delaware Basin Shales 700,000 160 90% 450 3.0—1,000 $4,500 22% $1.92 2 2 1
Woodford Shales 100,000 160 50% 250 2.2 14 400 $4,000 20% $2.27 1 2 10
Deep Bossier 180,000 320 90% 60 5.0 14 200 $10,000 25% $2.67 1 2 1
Other Emerging Unconventional Plays 1,045,000 160—100—-
Sub-total Emerging Unconventional 2,600,000 3,200 137 5,100 14 21
Note: Pro forma for acquisitions and acreage positions announced 10/26/06. Disclosure regarding unproved reserve estimates appears in slide 51.
CHK is hopeful that these plays prove to be successful over the next few years. CHK is hopeful that these plays prove to be successful over the next few years. If so, very significant value upside can be recognized. If so, very significant value upside can be recognized.
43
€400 Million Senior Notes Offering – November 2006
Fayetteville Shale
Acreage Position CHK Little Creek Field
Fayetteville Producing Fields
Active Rigs CHK Operated
Net Production vs. Operated Rig Count
Net Daily MMCFE
Net Production Operated Rig Count
18.0 16.0 14.0 12.0 10.0 8.0 6.0 4.0 2.0 0.0
9 8 7 6 5 4 3 2 1 0
Sep- 05 Dec -05 Mar-06 Jun-06 Sep- 06 Dec -06
W E 0’—Stratigraphic Profile
Hale Sandstone
Upper Fayetteville Shale
Lower Fayetteville Shale
Expected Economics Sensitivity Analysis
220%
200% 1.2 bcfe gross reserves 1.8 bcfe gross reserves 180% 2.4 bcfe gross reserves
160% 140% 120% 100% 80% 60% 40% 20%
5000
Average well cost of $2.5 mm/well
0% $6.00 $7.00 $8.00 $9.00 $10.00 Average NYMEX Natural Gas Prices
Operated Rigs
Unlevered IRR %
44
€400 Million Senior Notes Offering – November 2006
Delaware Basin Barnett/Woodford Shales
Acreage Position
B’
DEEP HALEY
OUTLINE
Path of Stratigraphic Profile Map
B
DELAWARE SHALE BASIN
OUTLINE
CHK Operated
Comparison of West Texas Shales and Ft. Worth Barnett Shale
Delaware Basin Shale
Ft. Worth Barnett Shale
Depth (feet) 10,000 – 16,000 6,500 – 8,500 Net thickness (feet) 400 – 1,000 50 – 400 Gas-in-place (bcf/section) 100 – 600 50 – 200
Recovery factor ??? 20% – 30%
Avg. well cost $3-5 Million ~$2.7 million
CHK’s upside here is potentially > 10x our Ft. Worth Barnett ShaleCHK’s upside here is potentially > 10x our Ft. Worth Barnett Shale upside – upside –~4x acreage size, ~3x gas in place. ~4x acreage size, ~3x gas in place.But lots of risk still. But lots of risk still.
Stratigraphic Profile
Barnett
Woodford
Expected Economics Sensitivity Analysis
60%
Base well cost + 15%
50% Base well cost of $4.5 MM/well Base well cost—15%
40% 30% 20%
10%
Average gross reserves of 3.0 bcfe/well
0% $6.00 $7.00 $8.00 $9.00 $10.00 Average NYMEX Natural Gas Prices
Unlevered IRR %
45
€400 Million Senior Notes Offering – November 2006
SE OK Woodford Play
Acreage Position
NW
Path of Stratigraphic Profile Map
SE
Active Rigs CHK Operated
Net Production vs. Operated Rig Count
Net Production Operated Rig Count
Net Daily MMCFE
3.5 3 2.5 2 1.5 1 0.5 0
Mar—4 Jun-04
Sep-04
Dec-04
Mar-05 Jun-05
Sep-05
Dec-05
Mar-06 Jun-06
Sep-06
Dec-06
| 7 |
|
6 5 4 3 2 1 0 |
NW Stratigraphic Profile SE
0’ -
2000’—BOOCH/HARTSHORNE
ATOKA 4000’—WAPANUCKA
CROMWELL
WOODFORD CANEY 6000’—HUNTON/VIOLA
8000’ -
10000’ -
11500’ -
Expected Economics Sensitivity Analysis
Base well cost + 15%
Base well cost of $4.0 MM/well Base well cost—15%
Unlevered IRR %
80% 70% 60% 50% 40% 30% 20% 10% 0%
Average gross reserves of 2.2 bcfe/well
| 6.00 |
|
7.00 8.00 9.00 10.00 Average NYMEX Natural Gas Prices |
46
€400 Million Senior Notes Offering – November 2006
Appalachian Gas Resource Plays
Play Types
NEW CBM YORK
ORANGEMEN
Tight Sands
Devonian Shale CAYUGA/SENECA & Tight Sands
Trenton-Black River & Tight Sands
TRUMBULL
CHK/CNR acreage
I A N
V A Y L S
N
E N
OHIO SOUTH BURNS P
CHAPEL
MD
COBB PODS
BUCKHANN
ON ARCH
BUCHANNON
HUBBALL CAYUGA
GASSAWAY
Charleston COBB
WV CORBIN
KENTUCKY KERMIT EGERIA
EGERIA
WARCO HUBBALL
KERMIT VIRGINIA MISC OTHER
CORBIN NY/PA DEEP
TRI-STATE SOUTH BURNS ARCH TRI-STATE
TRUMBULL
Substantial 3.5 million net acre position: largely held-by-production in well-established producing areas Multiple play types:
Devonian Shale and tight sands across large blanket formations
Trenton-Black River deep horizons in NY, PA and WV
Tight sands in WV, OH, NY, and PA
CBM in WV
Compelling value creation opportunities:
Drilling acceleration to enhance PV of inventory
Leverages CHK’s expertise in a largely under-explored basin
Only 1% of 400,000 wells drilled below 7,500’; <15 wells drilled below 15,000’
Improved application of science and transfer of technology from other basins
Fragmented basin that is ripe for consolidation
Extensive well workover opportunities with rates of return >50%
Premium gas price realizations: High btu gas; positive basis differentials to NYMEX (which we have partially hedged) vs. substantial discounts in various southwestern and western basins
Appalachia Gas Resource Plays 3Q06 Total Net Acreage Estimated Drilling Density (Acres) Assumed Risk Factor Risked Net Undrilled Wells Est. Avg. Reserves Per Well (Gr Bcfe) 3Q06 Booked PUD (Net Bcfe) 3Q06 Risked Net Unproved Reserves (Bcfe) Estimated Average Well Cost (Gr $000) Assumed Royalty Rate Finding Cost/Well ($/Mcfe) Current Op. Rig Count Planned YE 2006 Op. Rig Count October ‘06 Production Rate (Mmcfe/d)
Devonian Shale 2,900,000 160 25% 7,900 0.3 499 1,600 $425 13% $1.63 12 9
Other Appalachian Plays 600,000 800 5 300 2 1
Sub-Total Appalachia 3,500,000 160 35% 8,700 504 1,900 $8,000 14 10 130
Disclosure regarding unproved reserve estimates appears in slide 51
Big gas and acreage position next to very best U.S. gas market Big gas and acreage position next to very best U.S. gas market
Hope to transfer knowledge, technology and high activity levels to region Hope to transfer knowledge, technology and high activity levels to region
47
€400 Million Senior Notes Offering – November 2006
Appalachia
Acreage Map
Active Rigs CHK Operated
Net Production vs. Operated Rig Count
Net Daily MMCFE
160 140 120 100 80
Net Production Operated Rig Count
11/14/05 CHK Acquired
12 9 6 3 0
De c-03
Ma r -
04 Ju n-
04
Se p-
04
De c-04
Ma r -
05 Ju n-
05
Se p-
05
De c-05
Ma r -
06 Ju n-
06
Se p-
06
De c-06
Cambrian Typical Devonian Well
Stratigraphic Profile nn s y l v a n i a n
Expected Economics Sensitivity Analysis
Base well cost + 15%
Base well cost of $425,000/well Base well cost—15%
Average gross reserves of 0.3 bcfe/well
Operated Rigs
Unlevered IRR %
90% 80% 70% 60% 50% 40% 30% 20% 10% 0% $6.00 $7.00 $8.00 $9.00 $10.00 Average NYMEX Natural Gas Prices
48
€400 Million Senior Notes Offering – November 2006
Estimated Play Economics and Typical Type Curves
Est. Avg. Reserves Per Well (Gr Bcfe) Estimated Average Well Cost (Gr $000) Assumed Royalty Rate Implied Drilling Cost ($/mcfe) Average Production Rate of Type Well
Conventional 1st Month (mmcfe/d) 13th Month (mmcfe/d) 25th Month (mmcfe/d) 37th Month (mmcfe/d) 61st Month (mmcfe/d) 85th Month (mmcfe/d)
Gas Resource Plays
South Texas 1.8 $2,800 24% $2.11 2.57 0.74 0.50 0.40 0.33 0.29
Mountain Front 4.0 $8,000 22% $2.56 4.54 1.81 1.13 0.82 0.64 0.53
Est. Avg. Reserves Per Well (Gr Bcfe) Estimated Average Well Cost (Gr $000) Assumed Royalty Rate Implied Drilling Cost ($/mcfe) Average Production Rate of Type Well
Unconventional 1st Month (mmcfe/d) 13th Month (mmcfe/d) 25th Month (mmcfe/d) 37th Month (mmcfe/d) 61st Month (mmcfe/d) 85th Month (mmcfe/d)
Gas Resource Plays
Fort Worth Barnett Shale 2.4 $2,700 23% $1.49 2.33 0.77 0.52 0.41 0.34 0.29
Sahara 0.6 $900 19% $1.85 0.56 0.21 0.14 0.10 0.08 0.07
Ark-La-Tex Tight Gas Sands 1.0 $1,600 20% $2.00 0.95 0.32 0.22 0.17 0.14 0.12
Granite, Atoka and Cherokee Washes 1.4 $2,800 21% $2.53 1.69 0.44 0.30 0.23 0.19 0.17
Est. Avg. Reserves Per Well (Gr Bcfe) Estimated Average Well Cost (Gr $000) Assumed Royalty Rate Implied Drilling Cost ($/mcfe) Average Production Rate of Type Well
Emerging Unconventional 1st Month (mmcfe/d) 13th Month (mmcfe/d) 25th Month (mmcfe/d) 37th Month (mmcfe/d) 61st Month (mmcfe/d) 85th Month (mmcfe/d)
Gas Resource Plays
Fayetteville Shale 1.4 $2,500 15% $2.10 1.25 0.56 0.38 0.30 0.25 0.21
Deep Haley 7.0 $10,500 25% $2.00 7.66 2.72 1.71 1.28 1.03 0.87
Delaware Basin Shales 3.0 $4,500 22% $1.92 1.30 0.82 0.62 0.51 0.44 0.39
SE OK Woodford Shale 2.2 $4,000 20% $2.27 2.42 0.82 0.51 0.37 0.29 0.25
Deep Bossier 5.0 $10,000 25% $2.67 11.88 3.39 1.84 1.22 0.86 0.60
Est. Avg. Reserves Per Well (Gr Bcfe) Estimated Average Well Cost (Gr $000) Assumed Royalty Rate Implied Drilling Cost ($/mcfe) Average Production Rate of Type Well
Appalachia 1st Month (mmcfe/d) 13th Month (mmcfe/d) 25th Month (mmcfe/d) 37th Month (mmcfe/d) 61st Month (mmcfe/d) 85th Month (mmcfe/d)
Gas Resource Plays
Devonian Shale 0.3 $425 13% $1.63 0.21 0.07 0.05 0.04 0.04 0.03
Disclosure regarding unproved reserve estimates appears in slide 51
49
€400 Million Senior Notes Offering – November 2006
Corporate Information
Chesapeake Headquarters
6100 N. Western Avenue Oklahoma City, OK 73118
Web site: www.chkenergy.com
Common Stock – NYSE: CHK
Other Publicly Traded Securities CUSIP Ticker 4.125% Convertible Preferred Stock #165167875 N/A 5.0% Convertible Preferred Stock (2005 Series) #165167859 N/A 4.5% Convertible Preferred Stock #165167842 CHK PrD 5.0% Convertible Preferred Stock (2005 B Series) #165167826 N/A 6.25% Mandatory Convertible Stock #165167818 CHK PrE 7.5% Senior Notes Due 2013 #165167BC0 CHK13 7.5% Senior Notes Due 2014 #165167BG1 CHK14 7.0% Senior Notes Due 2014 #165167BJ5 CHKA14 7.75% Senior Notes Due 2015 #165167BA4 CHK15 6.875% Senior Notes Due 2016 #165167BE6 CHK16 6.375% Senior Notes Due 2015 #165167BL0 CHKJ15 6.625% Senior Notes Due 2016 #165167BN6 CHKJ16 6.50% Senior Notes Due 2017 #165167BS5 CHK17 6.25% Senior Notes Due 2018 #165167BQ9 CHK18 6.875% Senior Notes Due 2020 #165167BV0 CHK20 2.75% Contingent Convertible Senior Notes Due 2035 #165167BW6 CHK35 7.625% Senior Notes Due 2013 #165167BY2 CHKJ13
Contacts:
Marcus C. Rowland
Executive Vice President and Chief Financial Officer (405) 879-9232 mrowland@chkenergy.com
Jeffrey L. Mobley, CFA
Senior Vice President –
Investor Relations and Research (405) 767-4763 jmobley@chkenergy.com
50
€400 Million Senior Notes Offering – November 2006
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 “probable,” “possible” and “unproved” reserves, reserve “potential” or “upside” or 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 than 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.
51
€400 Million Senior Notes Offering – November 2006
Forward-Looking Statements
This report 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 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of oil and gas reserves, expected oil and gas production and future expenses, projections of future oil and gas prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and statements concerning anticipated cash flow and liquidity, our business strategy and other plans and objectives for future operations. In addition, statements 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 under “Risk Factors” in Item 1A of our 2005 Form 10-K filed with the Securities and Exchange Commission on March 14, 2006 and in the prospectus for our offering of senior notes filed on November 27th, 2006. These risk factors include the volatility of oil and gas 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 to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and gas reserves and projecting future rates of production and the amount and timing of development expenditures; uncertainties in evaluating oil and gas reserves of acquired properties and associated potential liabilities; our ability to effectively consolidate and integrate acquired properties; unsuccessful exploration and development drilling; declines in the values of our oil and gas properties resulting in ceiling test write-downs; lower prices realized on oil and gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower oil and gas prices could have on our ability to borrow; and drilling and operating risks.
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.
52