Forward Looking Statements

Transcription

1 November 6, 2009

2 Forward Looking Statements This document contains forward looking statements. All statements other than statements of historical facts included in this document, including but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans and objectives of management for future operations, are forward looking statements. Forward looking statements generally can be identified by the use of forward looking terminology such as may, will, expect, intend, estimate, anticipate, believe or continue or the negative thereof or variations thereon or similar terminology. These forward looking statements are subject to numerous assumptions, risks and uncertainties. Factors which may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by us in those statements include, among others, (i) the deteriorating economic conditions in the United States and globally, (ii) the difficult and adverse conditions in the domestic and global capital and credit markets, (iii) domestic and global demand for oil and natural gas, (iv) sustained declines in the prices we receive for our oil and natural gas adversely affecting our operating results and cash flow, (v) the effects of government regulation, permitting and other legal requirements, (vi) the quality of our properties with regard to, among other things, the existence of reserves in economic quantities, (vii) uncertainties about the estimates of our oil and natural gas reserves, (viii) our ability to increase our production and oil and natural gas income through exploration and development, (ix) our ability to successfully apply horizontal drilling techniques and tertiary recovery methods, (x) the number of well locations to be drilled, the cost to drill and the time frame within they will be drilled, (xi) drilling and operating risks, (xii) the availability of equipment, such as drilling rigs and transportation pipelines, (xiii) changes in our drilling plans and related budgets and (xiv) the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity. Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward looking statements. You are cautioned not to place undue reliance on such statements, which speak only as of the date of this document. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward looking statements, whether as a result of new information, future events or otherwise. 2

3 Key Takeaways Solid 3 rd Quarter o Gas production up 29% from previous quarter and 62% from same period in 2008 o Lease operating expenses down 26% from same period in 2008 o G&A expenses down 26% from same period in 2008 o EBITDAX up 27% from previous quarter o Debt level remains unchanged Operational Developments o Last horizontal Marcellus well at 4.2 Mmcfd average over 30 day period o 4 additional Marcellus wells expected to be completed during 4 th quarter o 19 new oil wells drilled o Continuing to expand Marcellus acreage 2010 Outlook o Strong balance sheet allows acceleration of Marcellus and conventional oil well drilling o 2010 budget process is continuing; expect to announce mid December 3

4 Production 2008 o High oil prices Focused on growing oil production Oil Production o Began vertical well testing in the Marcellus Shale MBbls st Half 2009 o Low Oil Prices Ceased oil development activity to reduce expenses Q1 '08 Q2 '08 Q3 '08 Q4 '08 Q1 '09 Q2 '09 Q3 '09 o Began Marcellus horizontal drilling 2 nd Half 2009 o Oil Prices Rebounding Restarted oil development activity o Marcellus horizontal drilling begins to grow significantly Mmcfe Gas Production +62% from Q % from Q Q1 '08 Q2 '08 Q3 '08 Q4 '08 Q1 '09 Q2 '09 Q3 '09 4

5 Daily Production & Pricing Production average per day 1 st Quarter 2 nd Quarter 3 rd Quarter 2 nd to 3 rd Quarter Change % Change Oil (Bbls) 2,013 2,019 1, % Gas (Mcf) 3,407 3,459 4, % Natural Gas Liquids (Bbls) % BOE 2,581 2,595 2, % Average Crude Oil Price per Bbls Realized Price (Before Derivatives) $39.85 $56.12 $64.77 $ % Realized impact from cash settled derivatives $18.01 $3.93 $(1.71) $ % Effective Realized Price $57.86 $60.05 $63.06 $ % Average Natural Gas Price per Mcf Realized Price (Before Derivatives) $5.15 $3.83 $3.64 $0.19 5% Realized impact from cash settled derivatives $1.66 $2.62 $2.69 $ % Effective Realized Price $6.81 $6.45 $6.33 $ % 5

6 Hedging as of November 6, 2009 Please note, all of the estimated hedged production is based on third quarter exit rate of 2,705 BOE per day including estimated average yearly declines. Year Crude Oil Volume at Volume Change Current Volume % of Current Avg. Production (1) Average Floor Average Ceiling Oct Dec MBbls (153 MBbls) 147 MBbls 85% $63.98 $ MBbls 588 MBbls 88% $62.71 $ MBbls 72 MBbls 228 MBbls 36% $63.42 $ MBbls 72 MBbls 12% $60.00 $ Natural Gas Oct Dec MMcf (330 MMcf) 330 Mmcf 79% $6.73 $ Bcf 720 MMcf 2.04 Bcf 135% $6.38 $ Bcf 480 MMcf 1.56 Bcf 115% $6.62 $ MMcf 240 MMcf 600 MMcf 49% $5.60 $ Based on September exit rate of 2,705 BOE/day 6

7 Selected Financial Highlights (in millions except per share data) 1 st Quarter 2 nd Quarter 3 rd Quarter 2 nd to 3 rd Quarter Change % Change Operating Revenue $ 8.9 $ 11.5 $ 13.0 $ % Gain on Cash Settled Derivatives $ 8.3 (1) $ 1.5 $ 0.8 $0.7 49% Total Revenue & Cash Settled Derivatives $ 17.2 $ 13.0 $ 13.8 $ 0.8 6% Lease Operating Expenses $ 5.2 $ 5.2 $ 5.7 $ 0.6 4% General & Administrative $ 3.8 $ 4.4 $ 2.8 $ % Loss on Disposal & Impairment $ 0.5 $ 0.6 $ 0.5 $ % Exploration Expense $ 1.1 $ (0.2) $ 0.4 $ % DD&A & Accretion $ 6.2 $ 6.6 $ 6.1 $ 0.5 8% Interest Expense $ 0.2 $ 0.4 $ 0.4 $ 0.0 0% Net Loss $ 1.3 $ 9.4 $ 1.2 $ % Net Loss per Share $ 0.04 $ 0.26 $ 0.03 $ % EBITDAX $ 8.7 $ 4.1 $ 5.2 $ % Cash Flow From Operations $ 2.9 $ 3.5 $ 6.4 $ % 1. Includes $4.6 million for the early settlement of certain oil derivatives associated with 2011 redeemed in the first quarter of

8 Liquidity (in millions) 1 st Quarter 2 nd Quarter 3 rd Quarter 2 nd to 3 rd Quarter Change % Change Revolving Credit Facility Borrowing Base Availability $ 80.0 $ 80.0 $ 80.0 $ 0.0 0% Amount Drawn $ 5.0 $ 15.0 $ 15.0 $ 0.0 0% Remaining Available $ 75.0 $ 65.0 $ 65.0 $ 0.0 0% Shareholders equity $ $ $ $ 1.4 1% Debt to Book Cap Ratio 2.2% 6.7% 6.8% n/a n/a Additional Capital Availability Cash and Cash Equivalents $ 4.0 $ 2.4 $ 4.7 $ % Remaining on Williams Carry n/a $ 31.0 $ 26.9 $ % 8

9 Operations: Butler County Marcellus Wells to Date o 4 Verticals o 1 Horizontal P. Knauff #1H Processing Plant Gas Processing DTI Pipeline o ~1,250 BTU gas o Current plant (5 Mmcfd) o 2010 expansion plans Leasing o ~22,400 net acres Added 8,357 net acres YTD Year end goal of additional 5K 10K net acres 3.00 P. Knauff #1H Production Marcellus Wells 2.50 Mmcfe/d Jun 09 Jul 09 Aug 09 Sep 09 Oct 09 Nov

10 Operations: Westmoreland County Marcellus Wells to Date o 3 Verticals o 5 Horizontals Eaglehouse #4H: In Line (~1.1Mmcf/d 30 day avg) Eaglehouse #7H: In Line (~700 Mcf/d 30 day avg) Panizzi #4H: In Line (~4.2 Mmcf/d 30 day avg) Panizzi #2H: Drilled awaiting completion Panizzi #3H: Drilling Eaglehouse #5H: Drilling Fourth Quarter Plan o Complete and put into line 3 additional wells o Drill 1 additional well Infrastructure Development o Installing tap on Equitrans line and constructing pipeline o Install tap on Texas Eastern (2010) Marcellus Wells Texas Eastern Pipeline Dominion Peoples Pipeline Equitrans Pipeline 10

11 Operations: Central PA Marcellus Wells to Date o 1 Vertical o 1 Horizontal Alder Run #1H: Drilling Columbia Pipeline Fourth Quarter Activity o Complete Alder Run #1H o Drill 1 additional well Infrastructure Development o Installing tap on Columbia 1711 line Alder Run #3H (to be drilled 4 th QTR) Alder Run #1H (Drilling) 11

12 Operations: Illinois Basin Conventional Drilling o Year to date drilling 19 drilled 9 wells completed and in line to date 8 wells awaiting completion o 2010 plan conventional wells Tertiary Recovery Projects o Bridgeport ASP Unit (Middagh Unit) Core testing and simulation results expected 4 th quarter 2009 Plan to commence injection June 2010 Middagh ASP Unit o Conformance gel test Commencing 4 th quarter

13 Preliminary Thoughts on program is likely to be designed around the following assumptions: gross (15 18 net) horizontal Marcellus wells o 1 company operated rig in Butler County, PA throughout the year (10 12 horizontal wells) o 1 Williams operated rig in joint venture areas throughout the year (10 12 wells) Carry should cover 8 10 of the 2010 wells (depending on cost) Rex carried for 90% of the cost to drill and complete wells (own 50%) Gas plant expansion in Butler County, PA to 40 Mmcfd o Expect to have operational by 4 th quarter Continued leasing in select areas shallow conventional oil wells Commencement of first Bridgeport ASP Unit 13

14 Upcoming Events Thomas Weisel Partners Alternative Energy & Natural Resources Conference New York Pritchard Capital Partners Appalachian Energy Forum Boston Capital One Southcoast 2009 Energy Conference New Orleans 14

15 Appendix Non-GAAP Reconciliation Tables 15

16 EBITDAX (in thousands) 1 st Quarter 2 nd Quarter 3 rd Quarter Net Loss from Continuing Operations $ (1,349) $ (9,437) $ (1,186) Add Back (Less): DD&A & Accretion 6,171 6,193 6,059 Non Cash Compensation (Income) (128) Interest Expense Impairment Expense Exploration Expense (Income) 1,082 (247) 370 Interest Income (1) (1) (2) Loss on Interest Rate Swap Loss (Gain) on Disposal of Assets 428 (28) 17 Unrealized Loss (Gain) on Derivatives 2,701 12, Income Tax Benefit (1,203) (5,841) (959) EBITDAX from Continuing Operations $ 8,700 $ 4,091 $ 5,

17 Clean Earnings (in thousands) 1 st Quarter 2 nd Quarter 3 rd Quarter Net Loss from Continuing Operations $ (1,349) $ (9,437) $ (1,186) Add Back (Less): Unrealized Loss (Gain) on Derivatives 2,701 12, Non Cash Compensation (Income) (128) Loss (Gain) on Disposal of Assets 428 (28) 17 Income Tax Benefit (1,203) (5,841) (959) Clean Earnings (Loss) from Continuing Operations $ 1,052 $ (2,621) $ (2,064) 17