 January 2007 JPMorgan High Yield Conference Exhibit 99.1 |
 1 1 Regulatory statements Regulatory statements Cautionary statements regarding forward looking statements This presentation includes forward-looking statements within the meaning of section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on certain assumptions and analyses made by the Company in light of its experience, on general economic and business conditions and expected future developments, many of which are beyond the control of the Company. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. Important factors that could cause actual results to differ materially from those made in or implied by the forward-looking statements herein include, among others, the Company’s ability to develop and replace reserves, the volatility of oil and natural gas prices, uncertainty of the Company’s liquidity, results of hedging transactions, uncertainties about estimates of reserves, the Company’s ability to successfully integrate acquired operations into the Company’s existing operations, drilling activity being less successful than expected, production variances from expectations, the availability of transportation facilities and other equipment, competition for properties, equipment, data and labor, changes in government regulation, risks associated with oil and gas drilling and production and other factors as described in the Offering Memorandum in conjunction with the Senior Notes being offered. Forward-looking statements are not guarantees of future performance and the Company's actual results, financial condition, liquidity and the development of its industry may differ materially from those indicated in or implied by such forward-looking statements. The Company’s forward-looking statements speak only as of the date of such statements and the Company undertakes no obligations to update such statements. |
 2 2 Management attendees Management attendees Mark Fischer, Chief Executive Officer Mark Fischer, Chief Executive Officer Co-founded Chaparral in 1988 Co-founded Chaparral in 1988 Prior experience with Exxon, TXO & Slawson Prior experience with Exxon, TXO & Slawson 34 years of experience in oil & gas sector 34 years of experience in oil & gas sector 42% owner of Chaparral 42% owner of Chaparral Joe Evans, Chief Financial Officer Joe Evans, Chief Financial Officer Joined Chaparral in 2005 as CFO Joined Chaparral in 2005 as CFO Former audit partner in Deloitte & Touche’s Former audit partner in Deloitte & Touche’s energy practice energy practice 27 years of experience in oil & gas sector 27 years of experience in oil & gas sector |
 3 3 Agenda Agenda Company overview Strategy and project overview Financials |
 4 4 Company highlights Company highlights Independent E&P company, engaged in the production, acquisition and development of oil & gas properties Core areas are the Mid-Continent and Permian Basin regions Third largest oil producer in Oklahoma Operating Highlights: Sept 2005 - $158 million CEI Bristol acquisition (115 Bcfe proved reserves) Oct 2006 - $500 million Calumet Oil acquisition (410 Bcfe proved reserves) Financial Highlights: Nov 2005 - $325 million bond placement Sept 2006 - $102 million private equity issuance (Chesapeake Energy) Jan 2007 - $325 million bond placement Company overview 1 Based on pro forma reserves as of 12/31/05 2 Pro forma for Calumet, based on the year ended 12/31/05 3 Annualized nine months ended 9/30/06, pro forma for Calumet and 2007 note offering Operational summary1 Dec. 2005PF Total proved reserves 1.0 Tcfe % Proved developed 63% % Crude oil 57% SEC pretax PV-10 ($61.04/bbl, $10.08/mcf) $2,139mm R/P ratio 24.7 years Avg. daily production2 111 Mmcfe Financial summary ($MM, except ratios) 9/30/06 PF 3 Avg. wellhead price ($/mcfe) $8.54 Oil and gas sales (prehedge) $352.0 Adjusted EBITDA $188.1 Revolving credit facility $292.8 Senior notes, issued December 2005 325.0 Senior notes, issued January 2007 325.0 Other long term debt 14.4 Total debt $957.2 Total debt / Adjusted EBITDA 5.1x Total debt / Boe¹ $5.74 Total debt / PD boe 1 $9.07 |
 5 5 Operational overview Operational overview Core area Growth area Acreage Field offices Headquarters Gulf Coast Reserves: 30.9 Bcfe, 3% of total Production: 3.0 Mmcfed, 3% of total Ouachita Uplift Midland Basin Delaware Basin Val Verde Basin Williston Basin Powder River Basin Greater Green River Basin San Juan Basin Anadarko Basin Arkoma Basin Fort Worth Basin Sabine Uplift Note: As of December 31, 2005, pro forma for the Calumet and CEI Bristol acquisitions North Texas Reserves: 17.4 Bcfe, 2% of total Production: 2.5 Mmcfed, 2% of total Rocky Mountains Reserves: 15.7 Bcfe, 2% of total Production: 2.5 Mmcfed, 2% of total Ark-La-Tex Reserves: 33.6 Bcfe, 3% of total Production: 8.3 Mmcfed, 8% of total Oklahoma City Company Total 2005 year-end proved reserves – 1.0 Tcfe 2005 average daily production – 111 Mmcfe Mid-Continent Reserves: 792.8 Bcfe, 79% of total Production: 85.1 Mmcfed, 77% of total Permian Basin Reserves: 109.7 Bcfe, 11% of total Production: 9.3 Mmcfed, 8% of total |
 6 6 Key investment considerations Key investment considerations Long-lived reserves with stable and predictable production profiles Long-lived reserves with stable and predictable production profiles Reserves are 57% oil and 84% operated with 90% located in the Mid- Reserves are 57% oil and 84% operated with 90% located in the Mid- Continent and Permian Basin Continent and Permian Basin Strong track record of replacing reserves at low cost through Strong track record of replacing reserves at low cost through acquisitions of mature properties and creating significant value acquisitions of mature properties and creating significant value through through enhancement enhancement Low risk drilling inventory with 793 proved locations and 2,897 other Low risk drilling inventory with 793 proved locations and 2,897 other drilling locations (November 2006) excluding Calumet drilling locations (November 2006) excluding Calumet Substantial upside potential with polymer and CO Substantial upside potential with polymer and CO 2 2 enhanced oil enhanced oil recovery projects recovery projects Current hedge position reduces risk associated with price volatility Current hedge position reduces risk associated with price volatility Generated profits in 17 of 18 years of existence Generated profits in 17 of 18 years of existence Experienced management and operational team averaging over 25 Experienced management and operational team averaging over 25 years of experience each years of experience each |
 7 7 618 435 304 249 0 100 200 300 400 500 600 700 800 900 1,000 1,100 2002 2003 2004 2005 2005 PF¹ Strong record of reserve and production growth Strong record of reserve and production growth Year-end reserves (Bcfe) 1 Pro forma for Calumet acquisition 25 19 15 13 0 5 10 15 20 25 30 35 40 45 2002 2003 2004 2005 2006E PF¹ Annual production (Bcfe) Acquisition growth: 14% Organic growth: 12% 1,000 42 24% 76% 38% 62% Chaparral Calumet Acquisition growth: 23% Organic growth: 12% 2002-2005 CAGR = 35% 2002-2005 CAGR = 26% |
 8 8 822% 794% 468% 610% % 100% 200% 300% 400% 500% 600% 700% 800% 900% 2002 2003 2004 2005 Impressive reserve replacement at attractive costs Impressive reserve replacement at attractive costs Reserve replacement ratio (%) Reserve replacement greater than 300% for 9 of the past 11 years; average Reserve replacement greater than 300% for 9 of the past 11 years; average of 582% per year of 582% per year 3-year fully developed FD&A cost of $1.82/Mcfe 3-year fully developed FD&A cost of $1.82/Mcfe $1.21 $1.82 $1.75 $2.28 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 2004 2005 Chaparral Industry¹ 3-year fully developed FD&A cost ($/Mcfe) Source: John S. Herold 1 Median of 25 domestic E&P companies |
 9 9 Agenda Agenda Executive summary Strategy and project overview Financials |
 10 10 Chaparral’s operating strategy Chaparral’s operating strategy Acquire mature properties and leasehold positions Acquire mature properties and leasehold positions Enhance Enhance production production through through recompletions recompletions and and workovers workovers Increase reserves and production through drilling of low-risk Increase reserves and production through drilling of low-risk inventory inventory Expand drilling focus to include shorter R/P areas (Gulf Coast, Expand drilling focus to include shorter R/P areas (Gulf Coast, etc.) to increase near-term earnings and balance long-lived etc.) to increase near-term earnings and balance long-lived reserves reserves Expand CO CO 2 2 pipeline pipeline infrastructure infrastructure and and develop develop 51 51 fields fields for for CO CO 2 2 tertiary recovery tertiary recovery Hedge production to stabilize cash flow Hedge production to stabilize cash flow |
 11 11 Oil and gas capital expenditures Oil and gas capital expenditures O&G capital expenditures ($MM) Component 2006E 2007 budget 2007 budget Percent of Drilling $130 $132 63% Enhancements 30 30 14% Minor Acquisitions 29 30 14% EOR projects 14 20 9% Subtotal $203 $212 100% Significant acquisitions 500 0 0% Total $703 $212 100% Continued focus on drilling 2007 drilling and EOR budget by area Note: Excludes potential ethanol plant investment ($30 million) and service company acquisition ($25 million) Mid-Continent 59% Ark-La-Tx 3% Permian Basin 19% Rocky Mountains 4% North Texas 7% Gulf Coast 8% |
 12 12 Acquisition strategy Acquisition strategy Acquisitions are a key part of Chaparral’s operating strategy 67% of reserves added 2003 - 2005 were through acquisitions Continue to pursue acquisitions in the $1 million to $20 million range Minor acquisitions represent 14% of planned 2007 oil and gas capex Selectively pursue larger strategic acquisitions Mature properties in the second half of their life Medium-to-long remaining life Operational control Enhancement or PUD drilling potential Properties with CO 2 tertiary recovery potential Acquisition investment criteria: 20% IRR 2:1 ROI 4 - 5 year payout Desired characteristics Acquisition philosophy |
 13 13 Calumet acquisition overview Calumet acquisition overview On October 31, 2006, Chaparral acquired Calumet Oil Company for $500 million Highlights (reserve data as of 9/30/06): 410 Bcfe of proved reserves, 233 Bcfe (57%) PDP, 397 Bcfe (97%) oil 92% of proved reserves in operated properties September production - 28 mmcfed (89% oil) Transaction benefits: Increased proved reserves by 62% to 1.0 Tcfe Increased proved oil reserves from 33% to 57% Stable long-lived reserves at attractive acquisition cost of $1.22/mcfe Significant development and EOR upside Increased production by 33% Expanded presence in Mid-continent Potential service company acquisition for $25 million Chaparral gas: 414 Bcfe 42% Chaparral oil: 203 Bcfe 20% Calumet oil: 368 Bcfe 37% Calumet gas: 14 Bcfe 1% YE 2005 pro forma proved reserves Total: 1.0 Tcfe |
 14 14 Enhancement projects Enhancement projects Typical enhancement projects Project inventory at 12/31/05 Install coiled tubing Repair casing leaks Install pumping units Install plunger lift Recompletions Install compression 693 identified projects 471 developed projects $17.6 million cost $486.9 million incremental cash flow 27.7x ROI >100% IRR Numerous enhancement opportunities on existing properties Enhancement projects represent 14% of planned 2007 capex |
 15 15 Low-risk drilling inventory Low-risk drilling inventory Drilling as a percentage of capex Drilling as a percentage of capex has increased from 22% in 2000 has increased from 22% in 2000 (excluding significant acquisitions) to 63% in 2007E (excluding significant acquisitions) to 63% in 2007E Lower risk infill or step-out wells (99% success rate in 2006) Lower risk infill or step-out wells (99% success rate in 2006) Inventory of 793 gross well locations in proved reserves with a net cost Inventory of 793 gross well locations in proved reserves with a net cost of $242 million (December 2005, excludes Calumet) of $242 million (December 2005, excludes Calumet) Inventory of 2,897 additional gross well locations with a net cost of Inventory of 2,897 additional gross well locations with a net cost of $1,720 million (November 2006, excludes Calumet) $1,720 million (November 2006, excludes Calumet) 14-year inventory of drilling locations at 2007 planned drilling rate of 14-year inventory of drilling locations at 2007 planned drilling rate of 117 operated wells and 153 wells operated by others 117 operated wells and 153 wells operated by others |
 16 16 Significant low-risk drilling inventory Significant low-risk drilling inventory 1 Proved locations are as of December 2005; other locations are as of November 2006 Inventory is before Calumet acquisition Drilling capital: Major plays $68 mm (45%), Other $84 mm (55%) Mid-Continent Other $67 Rockies $6 North Texas $11 Permian Haley Area $17 Permian Tunstill Field $12 Gulf Coast $16 Mid-Continent Cleveland Sand $14 Mid-Continent Fox Deese Springer $5 Mid-Continent SW Antioch Gibson Sand $4 Wells drilled or proposed (gross) Drilling locations (gross)¹ Continued focus on low-risk drilling 2007 Drilling and EOR budget ($MM) Mid- Continent Permian Basin 2005 2006E 2007E Operated by Chaparral 61 67 117 Operated by others 124 149 153 Total 185 216 270 Proved 793 146 647 Inventory Budget '07 Remaining Other 2,897 124 2,773 Total 3,690 270 3,420 |
   17 17 1950 1954 1958 1962 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 100 1,000 10,000 100,000 1 Mil 10 Mil Southwest Antioch Gibson Sand Unit Southwest Antioch Gibson Sand Unit Garvin County, OK Chaparral assumes operations Gas Mcf/mo Oil Bbl/mo Area affected by gas injection Chaparral’s second largest field by proved reserves prior to Calumet acquisition 7,000’ depth Chaparral acreage Field shutdown & plugging Unit Statistics OOIP (Mmbo) 121.8 Primary oil recovery (Mmbo) 21.2 Secondary oil recovery (Mmbo) 18.7 Cumulative gas recovery (Bcf) 255.1 Cumulative gas injection (Bcf) 142.5 Current gas-in-place (Bcf) 54.0 Gross reserves/well bcfe: 0.9 Gross CapEx / well $MM: $1.0 Company net acres: 9,520 Total seismic sq.mi.: 0 Avg working interest: 99% Potential drill locations: 80 Total net CapEx $MM: $85.7 Wells planned 2007: 4 2007 net CapEx $MM: $3.8 |
   18 18 Cleveland Sand Play Cleveland Sand Play 2006 Drilled Locations 2007 Well Locations Drilling or Recent Completions Sections with CEI Deep Rights Sections with CEI Interests Horizontal drilling Tight sand play 8,300’ depth Gross reserves/well bcfe: 1.4 Gross CapEx / well $MM: $1.9 Company net acres: 5,190 Total seismic sq.mi.: 0 Avg working interest: 60% Potential drill locations: 24 Total net CapEx $MM: $27.5 Wells planned 2007: 10 2007 net CapEx $MM: $14.0 |
 19 19 5 Acre Infill Locations 2007 Well Locations Surface facility location 22 27 30 32 33 35 Fox Deese Springer Unit Fox Deese Springer Unit Fox Deese Springer Unit WI – 79.44% (operated property) Size – 2,225 acres; Depth – 3300’ – 5500’ Cum. Rec. – 14MMBO (Primary & Secondary) Producing zones - Deese, Sims, Hoxbar & Morris Wells - 62 Producing, 46 Injection Very Lenticular in nature, tighter sands Upside Potential ID drilling from 10 acre spacing to 5 acre spacing Noble Energy began ID drilling the Milroy Deese Unit located 1 mile NW in 5/04. Production increased from 156 BOPD to 660 BOPD Pilot program underway with 4 wells First round have identified 24 PUD locations Potential recovery – 65-95 MBO/well Upside from CO2 EOR Gross reserves/well bcfe: 0.6 Gross CapEx / well $MM: $0.9 Company net acres: 2,225 Total seismic sq.mi.: 0 Avg working interest: 79.4% Potential drill locations: 100 Total net CapEx $MM: $72.1 Wells planned 2007: 7 2007 net CapEx $MM: $5.0 Carter County, OK |
   20 20 Tunstill Tunstill Field Play Field Play 2007 Well Locations 2006 Drilled Locations BELL CANYON SAND BELL CANYON SAND CHERRY CANYON SAND CHERRY CANYON SAND TUNSTILL FIELD TUNSTILL FIELD Delaware Basin Multi-pay environment 3,300-5,200’ depth Gross reserves/well bcfe: 0.5 Gross CapEx / well $MM: $1.1 Company net acres: 8,920 Total seismic sq.mi.: 10 Avg working interest: 100% Potential drill locations: 134 Total net CapEx $MM: $135.0 Wells planned 2007: 11 2007 net CapEx $MM: $11.6 Chaparral acreage |
 21 21 Haley Area Play Haley Area Play HALEY 36-4 - HALEY 38-2 - 0.02 MM 1.7 B 0.2 MM 3.8B 0.1 B 0.04 MM 0.3 B 0.04 MM 1.4 B 0.2 MM 8.6 B 0.5 MM 6.1 B 108 BOPD 293 MBO 1 MM 7.7 B 0.1 MM 13.8 B 0.8 MM 15.8 B .01 MM 0.5 B 0.8 MM 15.1 B 0.8 MM 7.0 B 0.3 MM 13.6 B 0 MM 0.2 B P&A 0.44 B 2.3 MM 28.1 B P&A 2.9 B 0.2 MM 1.6 B P&A .06 B 0.8 MM Current rate Mmcfd 10.9 B Estimated Ultimate Recovery as of 05/06 (Bcf) IP 29 MMCFD 0.5 B Comp Drlg Drlg Loving Co., Texas 2007 Deep Well Locations Drilling or Recent Completion Bone Springs, Strawn, Atoka and Morrow Play (17,700’ depth) High production rates Large reserve potential IP 24.3 MMCFD Drlg 0.4 MM 0.8 B 1.4 MM 19.4 B 0.2 MM 0.2 B 0 MM 0.3 B 21.7 B 22.2 MM HALEY 1-18 0.8 MM 5.9 B 12.9 MM 16.1 B 1.4 MM 1.7 B 16.9 MM 25.1 B 20.8 B 6.7 MM 0.02 MM 0 MM Chaparral Acreage Chaparral Mineral Rights Gross reserves/well bcfe: 3.2 Gross CapEx / well $MM: $4.9 Company net acres: 3,040 Total seismic sq.mi.: 29 Avg working interest: 56% Potential drill locations: 18 Total net CapEx $MM: $49.8 Wells planned 2007: 6 2007 net CapEx $MM: $16.6 Drilling Locations 2007 Bone Springs Locations |
 22 22 Gulf Coast Play Gulf Coast Play Large Active Prospects Counties with CEI Interests (XX sq.mi.) Square Miles of 3D Seismic 27 sq.mi. + 15 sq.mi. planned 40 sq.mi. + 60 sq.mi. planned Gross reserves/well bcfe: 2.7 Gross CapEx / well $MM: $2.2 Company net acres: 32,174 Total seismic sq.mi.: 545 Avg working interest: 72% Potential drill locations: 65 Total net CapEx $MM: $107.8 Wells planned 2007: 11 2007 net CapEx $MM: $16.3 |
 23 23 North Burbank Unit North Burbank Unit WI – 99.25% (operated property) Size – 23,080 acres; Depth - 3,000’ Cum. Rec. – 315MMBO (primary & secondary recovery) Producing zone - Bartlesville Reservoir – 2 Tier Wells - 215 producing, 142 injection, 601 TA Prod. Upside Potential Polymer EOR Phillips instituted polymer EOR Program from 1979 – 1986 as pilot area 1,440 Acres Production increased from 500 BOPD to 1,200 BOPD Shut down in 1986 due to low oil price Phillips estimated an incremental oil recovery for the polymer block A, 1,440 acre polymer pilot flood to be 2.36MMBO Calumet reinstituted polymer flood on 320 acres; $6MM cost, 15 well pattern Return 400 + wells to production History shows 8 – 15 BOPD per well C0 2 Enhanced Oil recovery Infill drilling to tighter Bartlesville interval |
 24 24 Substantial upside with Substantial upside with CO 2 tertiary recovery tertiary recovery CO 2 tertiary recovery projects Economics (4 proved reserve projects)¹ CO 2 project inventory 4 proved reserve projects 47 additional projects identified Represents 5% of planned 2007 capex CO 2 pipelines 352 miles of existing line 88 miles of expansion planned in 2007 through 2009 $58 million initial investment $159 million cash flow $65 million PV-10 2.7x ROI 45% IRR 1 As of 12/31/05 |
 25 25 Co2 Pipeline Co2 Pipeline Original Oil in Place Recovered 12-15% Primary Recovery 15-20% Secondary Recovery 4-11% Enhanced Recovery |
 26 26 Camrick Camrick area CO area CO 2 2 tertiary recovery tertiary recovery Camrick Area Beaver & Texas Counties, OK Chaparral’s largest property by proved reserves (6% of total) prior to the Calumet acquisition Consists of three unitized fields Operated with an average working interest of 54% CO 2 injection has improved gross production in Camrick Unit from 110 Bbls/day to 720 Bbls/day Expansion of CO 2 injection operations is currently underway and is expected to be implemented across all units Actual vs. forecast oil production (BOPM) Overview 1,000,000 100,000 10,000 1,000 PHASE 1 PHASE 1+2 1+2+NP 1+2+NP+NW 1+2+NP+NW+3 ALL THREE UNITS ACTUAL NW Camrick Unit, Perryton Unit and Camrick Unit Reservoir Morrow Net acreage 15,200 OOIP (Mmbo) 125.6 Primary oil recovery (Mmbo) 16.1 Secondary oil recovery (Mmbo) 13.4 Estimated tertiary CO2 recovery (Mmbo) 11.9 |
 27 27 CO CO 2 2 development potential development potential |
 28 28 Agenda Agenda Executive summary Strategy and project overview Financial overview |
 29 29 $33 $52 $82 $112 $188 2003A 2004A 2005A LTM 9/30/06 9/30/06 PF¹ 41.9 52.0 69.5 115 88 2003A 2004A 2005A 2006E 2006E PF¹ $74 $114 $201 $252 $352 2003A 2004A 2005A LTM 9/30/06 9/30/06 PF¹ Strong operating performance Strong operating performance Total oil and gas sales ($MM) Adjusted EBITDA ($MM) Capex for oil & gas properties ($MM) $180 $203 $153 $500 $212 $96 $57 $333 $703 2003A 2004A 2005A 2006E 2007 Budget Significant acquisitions Nine mos. Annualized Nine mos. Annualized 1 Pro forma for Calumet acquisition Avg. daily production (Mmcfe) |
 30 30 Capitalization and liquidity Capitalization and liquidity Capitalization ($MM) 1 Borrowings under the revolving credit facility at December 31, 2006 were approximately $637 million, excludes letters of credit totaling $1 million at September 30, 2006 2 Expected borrowing base of $500 million as adjusted for notes offering Liquidity ($MM) At September 30, 2006 Historical Pro forma for Calumet Pro forma for Calumet and new HY offering Cash and cash equivalents $102.7 $ 7.8 $7.8 Revolving credit facility $201.0 $607.6 $292.8 1 Other 14.4 14.4 14.4 8.500% Senior notes due 2015 325.0 325.0 325.0 8. 875% Senior notes due 2017 - - 32 5.0 Total debt $540.4 $947.0 $957.2 Total equity 172.9 172.9 172.9 Total capitalization $713.3 $1,119.9 $1,130.1 Pro forma for Calumet At September 30, 2006 and new HY offering Revolving credit facility availability 2 $207.2 Cash 7.8 Total liquidity $215.0 |
 31 31 ($MM, except for asset coverage ratios) Pro forma credit statistics Pro forma credit statistics Annualized 9 months ended September 30, 2006 Chaparral Calumet PF for acquisition & notes offering Reserves¹ Proved reserves (Mmboe) 103.0 63.7 166.7 Proved developed reserves (Mmboe) 71.1 34.4 105.5 % Proved developed reserves 69% 54% 63% % Oil 33% 96% 57% Production and financials Production (MMboe) 5.1 1.7 6.8 Reserves / production 20.2 37.5 24.5 PD reserves / production 13.9 20.2 15.5 Revenue pre hedge $242.5 $109.5 $352.0 EBITDA 118.7 69.4 188.1 Interest expense 38.7 -- 76.1 Total debt $540.4 $957.2 Asset coverage Total debt / Boe $5.25 $5.74 Total debt / PD Boe $7.60 $9.07 Credit statistics Total debt / EBITDA 4.6x 5.1x EBITDA / Interest 3.1x 2.5x 1 Reserves as of December 31, 2005 |
 32 32 Competitive cash margins and operating costs Competitive cash margins and operating costs Operating costs ($/Mcfe) Year ended Dec. 31, 9 months ended Sept. 30, 2006 2004 2005 Actual Pro forma¹ Production expense $1.86 $2.24 $2.63 $2.94 General and administrative expense 0.32 0.39 0.42 0.37 Interest expense 0.32 0.61 1.25 1.85 Cash unit operating costs $2.50 $3.24 $4.30 $5.16 Wellhead price received 5.99 7.94 7.85 8.54 Operating margin $3.49 $4.70 $3.55 $3.38 FD&A, 3-year $0.65 $1.13 FD&A, fully developed, 3-year $1.21 $1.82 1 Pro forma for Calumet acquisition and the notes offering |
 33 33 0% 10% 20% 30% 40% 50% 60% 70% 80% 2007 2008 2009 2010 2011 Gas Oil Active hedging program for downside insurance Active hedging program for downside insurance 80% of PDP oil production 80% of PDP oil production hedged through 2011 at hedged through 2011 at average price of $64.46 average price of $64.46 48% of PDP gas production 48% of PDP gas production hedged through 2008 at hedged through 2008 at average price of $7.65 average price of $7.65 44% of PDP gas production 44% of PDP gas production basis-hedged through June basis-hedged through June 2009 at average price of 2009 at average price of $0.90 $0.90 Hedged percent of PDP production as of January 5, 2007 Note: Dollars represent average strike price of hedges (includes all derivative instruments) $59.80 $67.52 $7.43 $8.92 $66.74 $65.28 $63.86 |
 34 34 Key investment considerations Key investment considerations Long-lived reserves with stable and predictable production profiles Long-lived reserves with stable and predictable production profiles Reserves are 57% oil and 84% operated with 90% located in the Mid- Reserves are 57% oil and 84% operated with 90% located in the Mid- Continent and Permian Basin Continent and Permian Basin Strong track record of replacing reserves at low cost through Strong track record of replacing reserves at low cost through acquisitions of mature properties and creating significant value acquisitions of mature properties and creating significant value through through enhancement enhancement Low risk drilling inventory with 793 proved locations and 2,897 other Low risk drilling inventory with 793 proved locations and 2,897 other drilling locations (November 2006) excluding Calumet drilling locations (November 2006) excluding Calumet Substantial upside potential with polymer and CO Substantial upside potential with polymer and CO 2 2 enhanced oil enhanced oil recovery projects recovery projects Current hedge position reduces risk associated with price volatility Current hedge position reduces risk associated with price volatility Generated profits in 17 of 18 years of existence Generated profits in 17 of 18 years of existence Experienced management and operational team averaging over 25 Experienced management and operational team averaging over 25 years of experience each years of experience each |