Rex Energy. SunTrust Utica Shale Tour Presentation. August 27, Responsible Development of America s Energy Resources

Transcription

1 Rex Energy SunTrust Utica Shale Tour Presentation August 27, 2012 Responsible Development of America s Energy Resources Rex Energy Corporation 476 Rolling Ridge Drive State College, PA P: (814) F: (814) E: InvestorRelations@RexEnergyCorp.com

2 Forward Looking Statements Except for historical information, statements made in this presentation, including those relating to significant potential opportunities, future earnings, resource potential, cash flow, capital expenditures, production growth, planned number of wells (as well as the timing of rig operations, natural gas processing plant commissioning and operations, fracture stimulation activities and the completion of wells and the expected dates that wells are producing hydrocarbons that are sold) and potential ethane sales pipeline projects are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements are indicated by words such as expected, expects, assumes, anticipates and similar words. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and the company's future performance are subject to a wide range of business risks and uncertainties, and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including (without limitation) the following: adverse economic conditions in the United States and globally; the difficult and adverse conditions in the domestic and global capital and credit markets; domestic and global demand for oil and natural gas; sustained or further declines in the prices the company receives for oil and natural gas; the effects of government regulation, permitting and other legal requirements; the geologic quality of the company s properties with regard to, among other things, the existence of hydrocarbons in economic quantities; uncertainties about the estimates of the company s oil and natural gas reserves; the company s ability to increase production and oil and natural gas income through exploration and development; the company s ability to successfully apply horizontal drilling techniques and tertiary recovery methods; the number of well locations to be drilled, the cost to drill and the time frame within which they will be drilled; the effects of adverse weather on operations; drilling and operating risks; the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services; the availability of equipment, such as drilling rigs and transportation pipelines; changes in the company s drilling plans and related budgets; the adequacy of capital resources and liquidity including (without limitation) access to additional borrowing capacity; uncertainties relating to the potential divestiture of the Niobrara assets, including the ability to reach an agreement with a potential purchaser on terms acceptable to the company; and uncertainties associated with our legal proceedings and the outcome. The company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on the company s risks and uncertainties is available in the company's filings with the Securities and Exchange Commission. The company's internal estimates of reserves may be subject to revision and may be different from estimates by the company's external reservoir engineers at year end. Although the company believes the expectations and forecasts reflected in these and other forward-looking statements are reasonable, it 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. 2

3 Estimates Used in This Presentation Hydrocarbon Volumes The SEC permits publicly-reporting oil and gas companies to disclose proved reserves in their filings with the SEC. Proved reserves are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. SEC rules also permit the disclosure of probable and possible reserves. Rex Energy discloses proved reserves but does not disclose probable or possible reserves. We may use certain broader terms such as resource potential, EUR (estimated ultimate recovery of resources, defined below) and other descriptions of volumes of potentially recoverable hydrocarbon resources throughout this presentation. These broader classifications do not constitute reserves as defined by the SEC and we do not attempt to distinguish these classifications from probable or possible reserves as defined by SEC guidelines. The company defines EUR as the cumulative oil and gas production expected to be economically recovered from a reservoir or individual well from initial production until the end of its useful life. Our estimates of EURs and resource potential have been prepared internally by our engineers and management without review by independent engineers. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. We include these estimates to demonstrate what we believe to be the potential for future drilling and production by the company. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. Estimates of resource potential and other figures may change significantly as development of our resource plays provide additional data and therefore actual quantities that may ultimately be recovered will likely differ from these estimates. Potential Drilling Locations Our estimates of potential drilling locations are prepared internally by our engineers and management and are based upon a number of assumptions inherent in the estimate process. Management, with the assistance of engineers and other professionals, as necessary, conducts a topographical analysis of our unproved prospective acreage to identify potential well pad locations using operationally approved designs and considering several factors, which may include but are not limited to access roads, terrain, well azimuths, and well pad sizes. For our operations in Pennsylvania, we then calculate the number of horizontal well bores for which the company appears to control sufficient acreage to drill the lateral wells from each potential well pad location to arrive at an estimated number of net potential drilling locations. For our operations in Ohio, we calculate the number of horizontal well bores that may be drilled from the potential well pad and multiply this by the company s net working interest percentage of the proposed unit to arrive at an estimated number of net potential drilling locations. In both cases, we then divide the unproved prospective acreage by the number of net potential drilling locations to arrive at an average well spacing. Management uses these estimates to, among other things, evaluate our acreage holdings and to formulate plans for drilling. Any number of factors could cause the number of wells we actually drill to vary significantly from these estimates, including: the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations, regulatory approvals and other factors. Potential ASP Units Our estimates of potential target areas, which we sometimes refer to as units, for which we may use an Alkali-Surfactant-Polymer ( ASP ) flood as a method of tertiary recovery have been prepared internally by our engineers and management. These estimates are based on our evaluation of the sand bodies underlying certain of our properties in the Illinois Basin. We have identified certain characteristics which we believe are desirable for potential ASP projects, including sand bodies with no less than 60 acres of areal extent and net reservoir thickness no less than 15 feet. We have subdivided the sand bodies to determine potential ASP target areas, which have been modeled such that no individual target area or unit would exceed 500 acres. We include these estimates to demonstrate what we believe to be the future potential for ASP tertiary recovery for the company. These estimates are highly speculative in nature and ultimate recoveries will depend on a number of factors, including the ASP technology utilized, the characteristics of the sand bodies and the reservoirs, geological conditions encountered, our decisions regarding capital, and the impact of future oil prices. 3

4 Rex Energy Overview Market Data NASDAQ: REXX Common shares outstanding: ~52.8 million 1 ~18% Ownership with corporate officers and directors Share Price: $ Market Capitalization: $677.4 million 2 52 Week Price Range: $ $ Q12 Avg. Daily Production of 62.5 Mmcfe/d Active operations in two basins: Appalachia Basin Illinois Basin Balance Sheet & Liquidity $15.6 million in cash $130 million debt with $235 million available $80 million of debt on senior credit facility with $185 million available $50 million of debt on second lien facility with $50 million available Borrowing base increased to $265 million from $255 million in May 2012; Undergoing mid-year redetermination 1. As of June 30, 2012 represents basic and diluted common shares outstanding 2. Data as of market close 8/24/2012 4

5 Strong Balance Sheet Liquidity Sources ($ millions) Cash as of 6/30/2012 $15.6 6M12 Op. Cash Flow Analyst Consensus $44.0 Subtotal $59.6 Availability on senior credit facility 1 $185.0 Availability on second lien facility $50.0 Subtotal $235.0 Total Sources of Liquidity $294.6 Remaining 2012 capital expenditure budget 2 $97.1 Liquidity as of January 1, $ Debt levels of 6/30/ The company does not attempt to budget for future acquisitions of proved and unproved oil and gas properties 3. Assumes no further changes to borrowing base 5

6 Commodity % Hedged Current Hedging Summary 80% 70% 60% 50% 40% 30% Current Production Hedged % of Current with Floor Crude Oil % of Current with Ceiling Avg. Floor Price Avg. Ceiling Price % 73% $ $ % 68% $ $ (1) 25% 25% $ $ % of Current with Floor Natural Gas % of Current with Ceiling Avg. Floor Price Avg. Ceiling Price 2012 (1) 62% 62% $ 4.37 $ (1) 78% 63% $ 4.35 $ % 10% 0% Commodity Oil Natural Gas Propane 1. Portions of production hedged with put spreads and collar contracts with short puts. See Appendix for more information % 23% $ 3.48 $ 4.11 Natural Gas Liquids/Propane % of Propane % of Liquids Price per Gallon Price per Barrel % 23% $ 1.03 $ % 25% $ 1.03 $43.26 Percentage hedged based on 3 rd Quarter 2012 mid-case guidance with standard decline 6

7 Utica Shale Overview ~ 106,200 gross (~72,200 net) acres Butler County Operations ~69,000 gross (~46,000 net) acres Cheeseman #1H Utica Well 5.3 MMcf/d 30-day rate (dry gas); 4.1 MMcf/d 60-day rate; 3.7 MMcf/d 120- day rate Ohio Warrior Prospect 15,400 acres Brace #1H - Drilled and completed in June 2012; First sales expected in September 2012 Ohio Warrior South Prospect ~ 5,600 gross (3,100 net) acres Guernsey #1H drilled and cased; currently drilling Noble #1H Targeting 20,000 net acres in Warrior Prospects Other operated Utica acreage ~ 16,200 gross (7,700 net) acres Expecting to drill 5 Utica Shale wells in 2012 Drill and complete 2 horizontal wells and drill 2 vertical wells in the Warrior Prospects Drill and complete 1 well in Butler Operated Area 2012 Utica Shale Drilling Program Well Counts Wells Drilled Fracture Stimulated Placed in Service Awaiting Completion

8 Ohio Utica Warrior North Prospect Exceeded +15,000 acres of leasehold in Warrior North Drilling operations began in 2Q-2012 Brace #1H well drilled and completed in June 2012 Encountered over 135 of Point Pleasant and 143 of Utica pay zone. Well SI for 60 days Brace #1H and G. Graham #1H wells approximately 1 mile from two CHK reported discoveries in the oil / condensate / liquids-rich gas zone Dominion East Ohio on schedule to connect Brace #1H well to sales ~ Sept 1 st, 2012 Over 100 net drilling locations in Warrior North Prospect 15 Mmcfe/d wet gas takeaway on Dominion East Ohio Full liquids recovery at first point of sales REXX Brace 1H Completed 4,175 Lateral Frac d with 17 stages EVEP Cairns 5H: 729 bbls of condensate per day; 2.2 MMcf/d; 587 bbls of NGLs/d 1.7 Mboe/d CHK Shaw H: 1.4 Mboe/d CHK Burgett # H: 1.2 Mboe/d REXX G. Graham Well Expected Location CHK Snoddy #6H: 1.3 Mboe/d CHK Buell H: 3.0 Mboe/d Located 10 miles south in Harrison County CHK Coniglio 6H: 1.1 Mboe/d CHK Mangun H: 1.5 Mboe/d CHK Neider H: 1.6 Mboe/d CHK Bailey H: 1.4 Mboe/d 1. See note on Potential Drilling Locations on page 3 8

9 Ohio Utica Warrior South Prospect ~ 5,600 gross (3,100 net) acres 1 Located in Guernsey, Noble and Belmont Counties Acreage within liquids rich window of the Utica Shale Guernsey #1H drilled and cased Noble #1H currently drilling Guernsey #2 will be drilled in 3Q Currently planning to frac one well in 4Q Joint Development Agreement with MFC Drilling and ABARTA Oil & Gas Co. 21 Potential net drilling locations 2 Expect to secure wet gas transporting capacity for Warrior South development Actively leasing in the area APC - Spencer A BOE/d APC Brookfield A-3H 600 BOE/d GPOR Groh 1-12H: 5,414 lateral; 15 stage frac; 1 frac stage 384 Mcf/d & 192 bbls condensate per day Antero Sandford Unit 1-H REXX Three Well Pad Guernsey#1H Noble#1H Guernsey #2H Antero Miley 5-H GPOR Wagner 1-28H Test Rate of 17.1 MMcf/d, 432 bbls of condensate/day, 1,881 bbls of NGLs/day assumes full ethane recovery GPOR Shugert 1-1H Proposed MWE Liquids Line Antero Rubel Unit 1-H PDCE Palmer Well APC Sharon A-1H 626 BOE/d 1. Subject to terms and conditions of farm-in agreement 2. See note on Potential Drilling Locations on page 3 9

10 Comparison of Warrior North and Warrior South to CHK Buell Well Rex Energy Guernsey 1H Noble/Guernsey County Chesapeake Kenneth Buell 8-H Harrison County Rex Energy Brace 1-H Carroll County Note: Increasing Point Pleasant Porosity to South Note: Increasing Point Pleasant/Utica Pay Thickness to North 10

11 Utica/Point Pleasant Potential in Pennsylvania Rex Energy Cheeseman 1-H Butler County Crawford County, PA Well Legacy Well Note: Utica/Point Pleasant Play in Northeast PA will be different from OH Play due to changes in rock type 11

12 Ohio Utica Proposed Processing Infrastructure REXX Carroll County Acreage Momentum Kensington Processing Facility: 600 Mmcf/d MWE Harrison I Processing & Fractionation Complex: 125 MMcf/d REXX Warrior South Acreage MWE Noble 1 Processing Complex: 200 MMcf/d Dominion Natrium Plant: 200 MMcf/d; 36,000 b/d fraction capacity Dominion Hastings Plant: 180 MMcf/d Over 1 BCF of planned processing capacity in Ohio Utica 12

13 Butler Operated Area Grubbs; Super- Rich Marcellus Test Butler Operated Area Burgh; Upper Devonian Test Location Pallack Pad Location Plesniak Pad Location Carson Pad; 2 wells completed Gilliland #11HB Burkett Well Consolidated acreage position of ~69,000 gross (~46,000 net) acres (Butler, Beaver and Lawrence Counties) Allows for minimal rig movement Decreases in drilling time Maximizes unitized acreage Access to three producing horizons, fourth potential horizon: Marcellus Shale: increasing EUR from previous range and increased liquids content in the NW portion of Butler acreage Upper Devonian / Burkett Shale / Rhinestreet: Increasing liquids content as compared to Marcellus Utica Shale: encouraging test well results Significant drilling inventory entering wells drilled awaiting completion 1 Super Frac design providing encouraging results Leasing program focused on increasing well counts Standard Fracture Stimulation Super-Frac Stimulation Drushel #3: Super-Frac Behm Pad; 3 wells completed Wells Drilled YTD Butler County Drilling Program Well Counts 2 Fracture Stimulated Placed in Service 2012 Butler County Drilling Program Well Counts 2 Awaiting Completion Includes two wells completed awaiting pipeline at the end of Includes one Utica Shale well in Butler County Wells Drilled Fracture Stimulated Placed in Service Awaiting Completion

14 UTICA MARCELLUS UPPER DEVONIAN SHALES Devonian Shales & Utica/Point Pleasant Butler County Area presents the potential of four productive reservoirs, three of which have liquids potential Upper Devonian & Marcellus Shales FORMATION NAME & DESCRIPTION RHINESTREET SHALE Mixed Organic & Non-organic Shale Reservoir 4 Marcellus reserves of 5.3 BCFE/well wet gas current EUR ~ 7.0 BCFE with full ethane recovery Gilliland 11-HB well produced at a restricted rate of 3.2 MMCFE from Burkett Shale; 16% increased liquids recovery compared to adjacent Marcellus MIDDLESEX SHALE Mixed Organic & Non-organic Shale GENESEE SHALE Mixed Organic & Non-organic Shale BURKETT SHALE Organic Black Shale Reservoir 3 Rhinestreet Shale appears to be gas and liquids bearing and not accessed by Burkett Shale fracture stimulations. Over 150 feet net thickness with high TOC s. Could be +30% increased liquids content as compared to Marcellus Utica Shale TULLY LIMESTONE HAMILTON SHALE Mixed Organic & Non-organic Shale MARCELLUS SHALE Organic Black Shale ONONDAGA LIMESTONE 200 Higher Reservoir 2 Point Pleasant Formation, consisting of organic shale and limestone similar to the Eagle Ford, is the main reservoir target UTICA SHALE 164 feet The Rex #1 Cheeseman well in Butler County tested at a 30-day rate of 5.3 MMcf/d, 60-day rate of 4.1 mmcf/d and 120-day rate of 3.7 MMcf/d from the Point Pleasant/Utica sequence Reservoir 1 Point Pleasant produces dry gas in Rex s Butler County acreage and indicates wet gas rich/condensate in Rex Ohio acreage POINT PLEASANT 130 feet TRENTON LIMESTONE 14

15 Marcellus Super Frac Type-Curve Results Wellhead Gas Rate (Mcf/d) Drushel 3H (150 ft design) Super Frac : Job Performed: April, 2011 Days on Production: + 1 Year Lateral Length: 3,000 ; 21 Stages Behm 1H (150 ft design) Super Frac : Job Performed: June, 2011 Days on Production: + 1 Year Lateral Length: 3,900 ; 26 Stages Carson 3H (150 ft design) Super Frac : Job Performed: March, 2012 Days on Production: ~60 days Lateral Length: 3,900 ; 26 Stages Carson 1H (225 ft design) Super Frac : Job Performed: March, 2012 Days on Production: ~60 days Lateral Length: 4,500 ; 20 Stages Pallack (2) (150 ft design) Super Frac : Job Scheduled: August, 2012 Lateral Length: 3,600 ; 24 Stages Plesniak (2) (150 ft design) Super Frac : Job Scheduled: September, 2012 Lateral Length: 3,600 ; 24 Stages Super Frac : Type-Curve Considerations as compared to YE BCFE Type Curve 24 hr IP = ~4,500 mscfd 30 day sales rate = 3,400 mscfd (No Change) Lateral Length: 4,000 (+14%) Stages: 23 (+82%) Sand Concentration: +6MM # (+34%) Well Cost: $6.2MM to $6.4MM (+17% to +21%) EUR: ~8 BCFE *(+51%) EUR: ~11.0 BCFE** (+51%) 5.3 BFCE Type Curve Decline Yr. 1: 66% Days of Production ~ 8.0 BFCE Type Curve Decline Yr. 1: 37% +30% Yr. 1 Cum Prod Super Frac Type Curve Behm 1H, Drushel 3H Average* 5.3 Bcfe Type Curve *No Ethane recovery ~24% Liquids ** Full Ethane recovery ~45% Liquids 15

16 Illinois Basin Conventional Oil Infill & Recompletions Illinois Basin ~ 23,525 gross (~ 23,495 net) acres in Illinois Basin Basin has produced over 4 billion barrels since 1906 Rex currently produces ~2,365 gross (1,840 net) barrels per day Rex technical team identified multiple recompletions and infill drilling opportunities in Gibson and Posey Counties, Indiana Mutliple zone re-completions Bypassed pay Infill drilling opportunities Recomplete and frac 7 wells in 3Q-2012 Drill 7 infill new producers in 3Q-2012 Infill and recompletions could add incremental ~ gross BOPD in 4Q 16

17 Lawrence Field ASP Update Middagh Pilot: Oil cuts in the Pilot increased from 1.0% to ~12.0% in total unit, with individual wells experiencing oil cuts above 20% Peak production was seen at 100+ BOPD Production averaged 50.1 gross BOPD in second quarter of 2012 as compared to 60.7 gross BOPD in the first quarter of Current Proved Reserves booking of 13% of Pore Volume continues to be confirmed Perkins-Smith 58 Acres Middagh Pilot 15 Acres Griggs 72 Acres Perkins-Smith Unit Pilot Expansion: ASP injection commenced in June of 2012 Initial project response expected by 2 nd quarter of 2013 Delta Unit Full Scale Commercial Expansion: Core studies and geologic mapping complete Drilling of additional pattern wells underway Injection line tie-in targeted for 3Q-2012 Expect to initiate tracer injection survey work in late 3Q-2012 On Track to begin ASP injection in 2Q-2013 Initial production response anticipated in 2014 ASP Recovery Incremental Production/Reserves Impact: Potential to double current Lawrence field production of approximately 1,000 gross BOPD in 2015 Potential to add approximately 1 million gross barrels of Proved reserves Delta Unit 17