Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of report (Date of earliest event reported): April 23, 2007
RANGE RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 0-9592 | 34-1312571 | ||
| (State or other jurisdiction of | (Commission | (IRS Employer | ||
| incorporation) | File Number) | Identification No.) |
| 777 Main Street, Suite 800 | ||
| Ft. Worth, Texas | 76102 | |
| (Address of principal | (Zip Code) | |
| executive offices) |
Registrant’s telephone number, including area code: (817) 870-2601
(Former name or former address, if changed since last report): Not applicable
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the
filing obligation of the registrant under any of the following provisions (see General Instruction
A.2. below):
| o | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |
| o | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |
| o | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |
| o | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
TABLE OF CONTENTS
| Item 2.02 Results of Operations and Financial Condition | ||||||||
| Item 7.01 Regulation FD Disclosure | ||||||||
| Item 9.01 Financial Statements and Exhibits | ||||||||
| SIGNATURES | ||||||||
| EXHIBIT INDEX | ||||||||
| Slide Presentation | ||||||||
Table of Contents
Item 2.02 Results of Operations and Financial Condition.
The
information on page 8 of the slide presentation referred to in Item 7.01 hereof and
furnished as Exhibit 99.1 hereto contains estimates of certain financial information regarding
Range Resources Corporation as of March 31, 2007, to be disclosed on April 23, 2007, and the
information set forth on such page is hereby incorporated into this Item 2.02 by reference.
Item 7.01 Regulation FD Disclosure.
Furnished as Exhibit 99.1 hereto is a slide presentation to be presented by Range Resources
Corporation at the Independent Petroleum Association of America Oil & Gas Investment Symposium in
New York on April 23, 2007.
Item 9.01 Financial Statements and Exhibits.
| (d) | Exhibits. |
| Exhibit | ||
| Number | Description | |
99.1
|
Slide presentation presented by Range Resources Corporation at the Independent Petroleum Association of America Oil & Gas Investment Symposium in New York on April 23, 2007. |
1
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| RANGE RESOURCES CORPORATION |
||||
| By: | /s/ Rodney L. Waller | |||
| Rodney L. Waller | ||||
| Senior Vice President | ||||
Date: April 23, 2007
2
Table of Contents
EXHIBIT INDEX
| Exhibit | ||
| Number | Description | |
99.1
|
Slide presentation presented by Range Resources Corporation at the Independent Petroleum Association of America Oil & Gas Investment Symposium in New York on April 23, 2007. |
3
Exhibit
99.1
| IPAA 2007 Oil & Gas Investment Symposium April 23, 2007 |
| Corporate Overview Appalachia Southwest Gulf Coast (1) Pro forma year-end 2006 to include the 2007 acquisitions and divestitures Market Cap ~ $5.0+ billion Reserve base (1) 1.9 Tcfe 82% natural gas 17 year reserve life Operations 2007 - 1,003 (757 net) wells Average ~ 39 rigs drilling Large acreage and drilling inventory (1) 3.3 million acres (2.5 million net) 10,500+ drilling projects in inventory |
| Key Value Drivers Proven Track Record Consistent record of growth at "top quartile" cost structure Built-In Growth Large, multi-year inventory of lower risk drilling projects drives built-in "double digit" growth profile Additional Upside Exciting portfolio of emerging plays provides additional near-term upside that could dramatically increase Range's value Strong Financial Position Strong, simple balance sheet with attractive hedges in place |
| 2007 Year-to-Date Scorecard Drilling program off to a terrific start 1Q '07 production of 306 Mmcfe/d was 19% higher than 1Q '06 Beat guidance by 9 Mmcfe/d 2 Divestitures Sold short life, high cost, mature properties for $237 million Sold at outstanding price 3 Acquisitions Buying incremental interests in existing properties for $374 million High quality, long life, low cost properties with sizeable upside potential Balance sheet strengthened 7 million share stock offering priced Debt to cap ratio at 39% with over-allotment Result = A Better, More Valuable Range |
| 2007 Divestitures Austin Chalk Divestiture Sold in February 2007 for $82 million Properties acquired from Stroud in mid-2006 Properties were determined not strategic to Range and classified as "held for sale" Reserve and operations excluded from Range's continuing operations Gulf of Mexico Divestiture Sold in March 2007 for $155 million Proved reserves of 38.6 Bcfe Lost 16 Mmcfe/d production beginning April 1 |
| 2007 Acquisitions Tonkawa Acquisition $30 million; closed in February 2007 Purchased minority owner's interest in the Tonkawa oil field Range now owns 100% working interest Southern Tarrant County Barnett Shale Acquisition $29 million; closed in April 2007 Purchased minority owner's interest in the Barnett Shale play Range now owns 100% working interest Nora Field Acquisition $315 million; scheduled to close in May 2007 Purchasing incremental interests in the Nora Field in Virginia Joint development plan will accelerate drilling |
| 2007 Acquisition Summary $374 million in total for the 3 acquisitions - $321 million for the reserves and acreage - $53 million for the Nora Field gathering system Proved reserves of 151 Bcfe $2.12/mcfe acquisition price(1) Currently producing 17 Mmcfe/day - - 90% natural gas (1) Excluding gathering system which has its own cash flow stream |
| Strong, Simple Balance Sheet Year-End 2005 Year-End 2006 Estimated 3/31/07 Estimated As Adjusted 3/31/07 ($ in millions) Bank borrowings $ 269 $ 452 $ 537 $ 417 (1) Sr. Sub. Notes 347 597 597 597 Total debt $ 616 $1,049 $1,134 $1,014 Common equity 697 1,256 1,304 1,584 (1) Total capitalization $1,313 $2,305 $2,438 $2,598 Debt-to-capitalization 47% 46% 47% 39% (1) Liquidity (2) $ 331 $ 348 $ 363 $ 487 (1) Adjusted to reflect $155 MM in asset sales proceeds applied to debt, Nora acquisition use of $315 MM and equity offering proceeds for 7 million shares plus 15% over-allotment at $36.28 applied to debt. The Nora acquisition is expected to close in May 2007 and the equity offering is scheduled to close in late April 2007. Liquidity is calculated by subtracting outstanding bank borrowings from the availability under the bank credit facility during each period. Strong liquidity position Target debt-to-cap of 40% reached |
| 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 153.9 158 159 164.7 177 182 210 215 229 233 244 250 257 264 289 294 306 0 0 0 Mmcfe/day 2003 2004 2005 Track Record of Consistent Growth 17 consecutive quarters of sequential production growth 2006 2007 154 158 159 165 177 182 210 215 229 233 244 250 257 264 Actual 289 294 306 1st quarter 2007 production set a new record and exceeded guidance of 297 Mmcfe/day |
| 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 153.9 158 159 164.7 177 182 210 215 229 233 244 250 257 264 289 294 306 312 327 341 Mmcfe/day 2003 2004 2005 Track Record of Consistent Growth Raising 2007 growth target to 16% 2006 2007 154 158 159 165 177 182 210 215 229 233 244 250 257 264 Actual Targets 289 294 306 |
| 2002 2003 2004 2005 2006 3 Year Average 5 Year Average Reserve growth 13% 18% 72% 20% 25% 52% 49% Drillbit replacement 114% 117% 217% 249% 377% 290% 237% Reserve replacement (1) 222% 285% 828% 365% 450% 526% 444% F&D costs per mcfe Drillbit only - Without acreage $1.39 $1.51 $1.13 $1.43 $1.40 $1.35 $1.37 With acreage $1.49 $1.59 $1.19 $1.53 $1.61 $1.50 $1.51 All sources - Excluding price revisions (2) (3) $1.24 $1.26 $1.21 $1.60 $1.94 $1.55 $1.51 Including price revisions (3) $0.90 $1.19 $1.20 $1.45 $2.10 $1.56 $1.47 Track Record of Consistent Growth Excludes reserve sales All sources with performance revisions, excludes price revisions Excludes ARO and other similar non-cash items |
| Drill Bit Finding Cost Track Record 2002 2003 2004 2005 2006 RRC 1.39 1.51 1.13 1.43 1.4 E&P Universe 1.44 1.62 1.89 2.54 2.95 Source: CSFB Research * Costs related to oil & gas exploration and development activities / extensions, additions & discoveries Drill Bit Finding Costs ($/Mcfe) DRILL BIT F&D COSTS* $1.39 $1.44 $1.51 $1.62 $1.13 $1.89 $1.43 $2.54 $1.40 $2.95 |
| Range - Low-Cost Producer RRC XTO KCS CHK DNR THX PXD NFX KWK WLL EAC PXP CWEI PPP CRK PQUE EPL SFY FST SGY 3.54 3.85 3.93 4.14 4.48 4.56 4.63 4.63 4.9 5.09 5.11 5.11 5.57 5.58 5.69 6.15 6.3 6.95 7.74 8.08 Range's break-even NYMEX gas price was $3.54 per mcfe in 2005 Source: Banc of America Securities High Yield Research Report of 5/2/06 Companies include (in alphabetical order): Chesapeake, Clayton Williams, Comstock, Denbury, Encore, Energy Partners, Forest, Houston Exploration, KCS Energy, Newfield, Petroquest, Pioneer, Plains, Pogo, Quicksilver, Range Resources, Stone, Swift, Whiting, XTO Per Mcfe Range Resources |
| Free Cash Flow - The Key to Consistent Growth AVG Asset Intensity % 25 29 29 29 33 37 41 46 46 46 46 50 53 55 58 59 63 66 72 46% 29% 2007E MAINTENANCE CAPEX / CASH FLOW Source: Deutsche Bank, January 2007 Companies include (in alphabetical order): Anadarko, Apache, Bill Barrett, Chesapeake, Devon, EnCana, EOG, EXCO, Forest, Newfield, Noble, Pioneer, Pogo, Quicksilver, Southwestern, Ultra, XTO Asset intensity Range Resources |
| Range's Growth Plan is Working Reserve Growth Drivers (Tcfe) YE 2005 YE 2006 Pro forma YE 2006 (2) Proved Reserves 1.4 1.8 1.9 Drilling Inventory (1) 1.4 2.0 2.7 Emerging Plays (1) 2.0 to 3.2 4.7 to 7.2 5.5 to 8.7+ Total 4.8 to 6.0 8.5 to 11.0 10.1 to 13.3+ (1) Net unrisked reserve potential (2) Includes 2007 Acquisitions and Divestitures |
| Range - "A lot of ways to win" Coal Bed Methane Tight Oil Sands Tight Gas Sands Shale Resource Plays Tight Gas Sands |
| 166 111 3,038 10,413 187 18 Net Bcfe Unrisked Reserves Gross Wells in Inventory Risk Profile Mississippi Norphlet Gulf Coast N. La/Miss. Hosston/CV Appalachia Trenton Black River Midcontinent Deep Anadarko Midcontinent Morrow/ Springer East Texas Stacked Pay Appalachia Oriskany Midcontinent Tonkawa Permian San Andres Permian Cisco/ Canyon Appalachia U. Dev. Sands/ Berea Appalachia Clinton/ Medina Appalachia Coalbed Methane High Medium 10,542 3,391 Total Low Fort Worth Barnett Shale Built-In Future Growth 2.7 Tcf unbooked reserves, primarily low-risk tight sand, shale and CBM reserves Large, Multi-Year Drilling Inventory |
| Emerging Plays Upside 5.5 to 8.7+ Tcf Play Acreage Net Unrisked Reserve Potential Activity Devonian Shale - Pennsylvania 420,000 acres 2.5 to 5.0+ Tcf Drilling and leasing Devonian Shale - Virginia & W. VA 378,000 acres (1) 0.8 to 1.5 Tcf Spud well 2H '07 Barnett Shale - Eastern Extension 20,000 acres 1.0 Tcf 1st well drilling Barnett Shale - Permian 20,000 acres 400 Bcf Spud 1st well 1H '07. Woodford, Fusselman, Wolfcamp potential Floyd Shale - Black Warrior Basin 50,000 acres 500+ Bcf (1) Spud well 2H '07 CBM: Widen Field - West Virginia 77,000 acres 200 Bcf Drilled pilot. Dewatering wells Woodford Shale - Oklahoma 5,000 acres 100 Bcf Drilling and leasing (1) Includes ~300,000 acres at Nora. Range owns the minerals plus a 50% working interest. |
| Nora Transaction Summary Range to pay $315 million to Equitable Resources $262 million for reserves and acreage $53 million for the gathering system Range and Equitable will then own 50% interest in 1,600 producing wells, 300,000 acres of leasehold and the gathering system Range will retain mineral and royalty interests covering approximately 80% of the acreage (230,000 acres) Closing scheduled for May, subject to HSR clearance Range acquires: 14.3 Mmcfe/d of production Range working interest on all existing wells increases from 29%, on average, to 50% Range interest in future tight gas sand and shale wells increases from 20% to 50% Range deep exploration rights increase from 0% to 50% Range interest in the gathering system increases from 0% to 50% |
| Nora Transaction Benefits Joint development plan Equitable to drill CBM wells and manage the gathering system Range to drill non-CBM - tight gas, shale gas and deeper formations Interest aligned with both companies being 50/50 owners Capitalizing on relative strengths of each company Will accelerate development of the field Significant upside at Nora Low risk CBM and tight gas drilling Tremendous shale gas potential Deeper formations are an "unknown" |
| Nora Field - Multiple Horizon Potential 1,100 - 2,500 4,000 - 5,000 5,000 - 6,000 CBM TIGHT GAS SANDS DEVONIAN SHALE SILURIAN / ORDOVICIAN 12,000 Depth in feet |
| Nora CBM - 60 Acre Spacing Working interests equalized in production, acreage, depths and gathering system Pre- deal Post- deal Net Mcfe/day 22.5 29.1 Gross Wells 1,126 1,167 Net Wells 339 533 Drilling 275 CBM wells in 2007 Undrilled Drilled New Acreage |
| Nora CBM Upside Summary Gross gas in place 2.4 Tcf Range recovery estimates 70% 80% 1.7 Tcf 1.9 Tcf Range average NRI 54% 54% Net remaining recoverable 0.8 Tcf 1.0 Tcf Currently booked proven reserves 0.2 Tcf 0.2 Tcf Net unbooked reserves 0.6 Tcf 0.8 Tcf Higher recoveries will be achieved through development drilling, infill drilling and recompletions |
| Nora Tight Gas Sand Wells Pre- deal Post-deal Net Mcfe/day 3.1 10.8 Gross Wells 449 579 Net Wells 27 265 Undrilled Drilled New Acreage |
| Downspacing Offers Additional Nora Tight Gas Sand Upside Field Delineation 100 locations still to be drilled on existing 112 acres spacing Infill Will test 60 acre spacing Current spacing recovery ~50% of gas in place Infill wells will potentially increase recovery to 80% Up to 600 potential infill locations Net tight gas sand recoverable reserves 100 potential 112 acre spacing remaining 15 Bcfe 600 potential infill locations 113 Bcfe 128 Bcfe |
| Nora Field Growth Profile Outstanding Production Growth with Low Finding Costs Net MCFED |
| Nora Devonian Shale Potential Clinchfield # 203 Cumulative recovery 1.4 Bcf Estimated ultimate recovery 2.2 Bcf Recent Horizontal Well 37 vertical wells producing from Devonian shale on Nora acreage; co-mingled with tight gas sands BIG SANDY FIELD 2.5+ Tcf |
| Nora Shale - Significant Upside Cross-section of logs indicates Devonian Shales exists across the Nora Field area |
| 73,000 gross (64,000 net) acres of leasehold 94% of leasehold in the Core and Expanding Core 8 rigs currently operating Production over 45 Mmcfepd Ellis County, eastern extension. Well spud on April 9th High quality technical team is leading to additional opportunities Barnett Shale Potential 2.0 Tcf Upside |
| WOC Simul-frac 1st week of May 8 Mmcf/d 12.2 Mmcf/d 8.3 Mmcf/d Simul-frac 2,200 acres 9 Wells drilled 25 Wells to be drilled 2 Wells waiting on completion Southern Tarrant County Barnett Acreage Range recently increased its ownership from 75% to 100% working interest |
| 1 Tcf Upside net to Range 20,000 net acres Barnett stratigraphy similar to productive Barnett to the West Expecting approx. 400 ft. of Barnett in Moore #1H Subthrust Barnett (not involved in Ouachita complexity) Barnett Shale - Eastern Extension EOG / HARDING ACTIVITY PIPELINE PIPELINE Johnson Ellis Hill EOG / WESTSIDE RECENT COMPLETIONS MOBIL COCKERHAM #1 1969 DEEP TEST Ouachita Thrust Fold Belt MOORE #1H DRILLING RANGE / VENUS AREA 7 WELLS PRODUCING 5 WELLS WAITING ON COMPLETION Range acreage Completed gas wells Drilling / Waiting on completion |
| PA Devonian Shale 2.5 to 5+ Tcf Potential 420,000 acres leased 21 vertical wells and 2 horizontal wells currently online First three vertical wells appear to have 600-1,000 Mmcfe of reserves each Finding and development costs expected to be $1.30 based upon early tests $5.00 NYMEX gas price yields ~28% IRR OH WV PA Devonian Shale |
| Shale Plays - 787,000 Acres Devonian Shale 420,000 acres 60 vertical - 8 horizontal wells 2007 $1.30 early estimated F&D costs 2.5 to 5.0+ Tcf reserve potential Floyd Shale 50,000 acres Drill first well 2H 2007 500+ Bcf potential Permian Basin Barnett 20,000 acres Stacked pay potential 400 Bcf potential Drill first well 2007 FW Barnett Shale 64,000 acres Drill 50 wells 2007 2.0 Tcf potential Woodford Shale 5,000 acres Drill first well 1H07 100 Bcf potential Dev. Shale-VA. & W. VA. 378,000 acres, 228,000 net Drill first well 2H07 0.8 to 1.5 Tcf potential |
| Why Invest in Range? Proven Track Record of Growth 17 consecutive quarters or production growth at low cost 8 to 11 Tcfe of upside relative to 1.9 Tcfe proven reserve base Built-In Growth (2.7 Tcfe) 2.7 Tcfe in inventory (10,500+ low risk, low F&D, good ROR drilling locations) Significant Upside (5.5 to 8.7+ Tcfe) 5.5 to 8.7+ Tcfe in emerging plays (shale plays and CBM) Valuation Has Significant Room to Run Much of the potential value from the drilling inventory and emerging plays not reflected in the stock price |
| Statements concerning future capital expenditures, production volumes, reserve volumes, reserve values, reserve potential, number of development and exploration projects, finding costs, operating costs, overhead costs, cash flow and earnings are forward-looking statements. These statements are based on assumptions concerning commodity prices, recompletions and drilling results, lease operating expenses, administrative expenses, interest and other financing costs that management believes are reasonable based on currently available information; however, management's assumptions and the Company's future performance are both subject to a wide range of business risks and there is no assurance that these results, goals and projections can or will be met. This presentation includes certain non-GAAP financial measures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found on our website at www.rangeresources.com. The SEC has generally permitted oil and gas companies, in their filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation test to be economically and legally producible under existing economic and operating conditions. We use the terms 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. 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. Forward-Looking Statements |
| Appendix |
| Appalachian Basin Overview Largest onshore basin in the U.S. by aerial extent - More than 1 million wells drilled - Has produced over 70 Tcfe Much of the basin remains unexploited - Less than 1% of wells drilled below 7,500 feet Large untapped CBM potential - 12 Tcf Large untapped shale potential - 20 Tcf |
| 5 6 7 8 9 10 31.33 43.21 55.83 69.19 83.27 98.22 Rate of return (%) 43% at $6.00 63% at $7.50 83% at $9.00 287,000 owned acres; some include royalty High-quality CBM field at 2,500 feet with deeper tight gas production at 5,000 feet Low finding cost of less than $1.00/mcf for CBM 2,800+ undrilled CBM locations Nora Area CBM Summary NYMEX Gas Price $ CBM Economics (IRR) Based on Current Well Costs $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 |
| Virginia CBM Reserve Potential Nora / Haysi is one of the most geologically defined projects at Range 50 core holes to determine coal thickness for original coal mining 550+ conventional wells drilled through coals to tight gas sands below coals 1,050 wells drilled in the CBM field Contours represent total coal thickness in inches CNX Oakwood Field |
| CBM Drilling History 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 Nora 2 12 40 44 54 39 42 5 49 74 56 79 55 46 42 74 96 158 227 290 Haysi 5 16 26 35 Widen 11 10 Number of CBM wells drilled per year FORECAST P |
| Typical Nora CBM Production Profile 400 Mmcf EUR PHASE 2: Desorption WATER BBL/D Mcf/d PHASE 1: Dewatering of fractures |
| West Virginia - Widen / Fola Fields West Virginia - Widen / Fola Fields 10 CBM wells testing Net production 1.4 Mmcfd CBM Pilot Widen Field 6,000 Acres under lease 100% WI, 87.5% NRI Widen Field 73,500 Acres owned 100% WI, 100% NRI Fola Field 9,500 Acres under lease 100% WI, 87.5% NRI |
| 4 5 6 7 8 9 3 Bcf 14 25 38 55 74 80 2 Bcf 11 20 30 40 50 60 Barnett Shale Gas Fields Note: Based on Range Resources' data and estimates Avg. Project Economics (IRR) Rate of return (%) Assuming 3 Bcf, ROR would be: - 25% at $5.00 - 49% at $6.50 - 71% at $8.00 Assuming 2 Bcf, ROR would be: - 19% at $5.00 - 36% at $6.50 - 51% at $8.00 NYMEX Gas Price $ Based on Current Well Costs Barnett Acreage: - 73,000 (64,000 net) 3 Bcf 2 Bcf |
| (1) Three-year average of F&D costs (2) Excludes non-cash deferred comp plan mark-to-market, no G&A capitalized (3) Includes any preferred stock dividends Unit Costs Are a Key Focus 2003 2004 2005 2006 2007E Reserve 1.43 1.15 1.33 1.56 2 LOE 0.63 0.65 0.76 0.9 0.95 Production taxes 0.22 0.29 0.36 0.37 0.4 G&A 0.31 0.29 0.34 0.35 0.38 Interest 0.38 0.36 0.44 0.57 0.69 Reserve Rep (1) $1.43 $1.15 $1.27 $1.56 $2.00 LOE $0.63 $0.65 $0.76 $0.90 $0.95 Prod. taxes $0.22 $0.29 $0.36 $0.37 $0.40 G&A (2) $0.31 $0.29 $0.34 $0.35 $0.38 Interest (3) $0.38 $0.36 $0.44 $0.57 $0.69 Total $2.97 $2.74 $3.17 $3.75 $4.42 $/mcfe |
| 2003 2004 2005 2006 2007E 0.93 1.66 2.85 3.04 4.33 2.36 2.81 4.12 4.6 5.33 Margins are Expanding Assumes $7.50 gas and $50 oil for 2007. (2) Three-year average. 2007E estimated using $2.50 for 2007. Realized Prices (1) $3.90 $4.40 $6.02 $6.79 $7.75 Cash Costs 1.54 1.59 1.90 2.19 2.42 Cash Margin 2.36 2.81 4.12 4.60 5.33 Reserve Rep. (2) 1.43 1.15 1.27 1.56 2.00 Full Cycle Margin $0.93 $1.66 $2.85 $3.04 $3.33 |
| Hedging Status As of 4/17/07 GAS GAS GAS OIL OIL OIL % Volume Hedged Average Hedge Prices % Volume Hedged Average Hedged Prices 2007 Swaps 39% $9.13 - - 2007 Collars 40% $7.13 - $9.99 65% $53.46 - $65.33 2008 Swaps 38% $9.42 - - 2008 Collars 20% $7.93 - $11.39 82% $59.01 - $75.36 2009 Collars - - 45% $62.00 - $75.94 Weighted average gas floors are $8.12 for 2007 and $8.91 for 2008 for volumes hedged. For 2007, on a total equivalent basis, 72% of production is hedged For 2008, on a total equivalent basis, 59% of production is hedged For 2009, on a total equivalent basis, 8% of production is hedged |