Rex Energy Corporate Presentation. September 2014

Transcription

1 Rex Energy Corporate Presentation September 2014

2 Forward Looking Statements and Presentation of Information Forward-Looking Statements Statements in this presentation that are not historical facts 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. For example, we make statements about significant potential opportunities for our business; future earnings; resource potential; cash flow and liquidity; capital expenditures; reserve and production growth; potential drilling locations; plans for our operations, including drilling, fracture stimulation activities, and the completion of wells; and potential markets for our oil, NGLs, and gas, among other things, that are forward looking and anticipatory in nature. These statements are based on management s experience and perception of historical trends, current conditions, and anticipated future developments, as well as other factors believed to be appropriate. We believe these statements and the assumptions and estimates contained in this presentation are reasonable based on information that is currently available to us. However, management's assumptions and the company's future performance are subject to a wide range of business risks and uncertainties, both known and unknown, and we cannot assure that the company can or will meet the goals, expectations, and projections included in this presentation. Any number of factors could cause our actual results to be materially different from those expressed or implied in our forward looking statements, including (without limitation): economic conditions in the United States and globally; domestic and global demand for oil and natural gas; volatility in oil, gas, and natural gas liquids pricing; new or changing government regulations, including those relating to environmental matters, permitting, or other aspects of our operations; the geologic quality of the company s properties with regard to, among other things, the existence of hydrocarbons in economic quantities; uncertainties inherent in the estimates of our oil and natural gas reserves; our ability to increase oil and natural gas production and income through exploration and development; drilling and operating risks; the success of our drilling techniques in both conventional and unconventional reservoirs; the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future; the number of potential well locations to be drilled, the cost to drill them, and the time frame within which they will be drilled; 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 infrastructure, such as transportation pipelines; the effects of adverse weather or other natural disasters on our operations; competition in the oil and gas industry in general, and specifically in our areas of operations; changes in the company s drilling plans and related budgets; the success of prospect development and property acquisition; the success of our business and financial strategies, and hedging strategies; conditions in the domestic and global capital and credit markets and their effect on us; the adequacy and availability of capital resources, credit, and liquidity including (without limitation) access to additional borrowing capacity; and uncertainties related to the legal and regulatory environment for our industry, and our own legal proceedings and their outcome. Further information on the risks and uncertainties that may effect our business is available in the company's filings with the Securities and Exchange Commission. We strongly encourage you to review those filings. Rex Energy does not assume or undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Presentation of Information The estimates of proved reserves as of June 30, 2014 in this presentation are based solely on the review and calculations of our internal reservoir engineers and have not been prepared or audited by our independent external reserve engineers. The estimates of proved reserves as of December 31, 2013 in this presentation are based on a reserve report of our independent external reserve engineers. We believe the data we (i) prepared and reviewed internally in connection with our estimates of proved reserves as of June 30, 2014, and (ii) we prepared and supplied to our external reservoir engineers in connection with their preparation of the 12/31/2013 reserve report, and, in each case, the assumptions, forecasts, and estimates contained therein, are reasonable, however, we cannot assure that they will prove to have been correct. Estimates of reserves can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Please see slide 3 for additional information about our estimates of reserves. In this presentation, references to Rex Energy, Rex, REXX, the Company, we, our and us refer to Rex Energy Corporation and its subsidiaries. Unless otherwise noted, all references to acreage holdings are as of December 31, 2013 and are rounded to the nearest hundred. All financial information excludes discontinued operations unless otherwise noted. All estimates of internal rate of return (IRR) are before tax. 2

3 Forward Looking Statements and Presentation of Information 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 hydrocarbons 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. In addition, we are prohibited from disclosing hydrocarbon quantities that do not constitute reserves in documents filed with the SEC. 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 materially 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. 3

4 Rex Energy Company Overview Focused on developing liquids-rich acreage in the Appalachian and Illinois Basins Appalachian Basin: Targeting wet-gas windows in the Pennsylvania Marcellus and Ohio Utica Shales Illinois Basin: Strong cash flow; 100% oil production; low decline assets; opportunity for conventional infill drilling Appalachian Basin Current (1) Net Acreage ~107,000 Pro Forma Net Acreage ~314,000 (2) Proved Reserves (3) 2Q'14 Production 1,014.4 Bcfe MMcfe/d Warrior Prospects Net Acreage ~21,300 Illinois Basin Net Acreage ~81,700 Proved Reserves (3) 7.2 MMBoe 2Q 14 Production 2.3 MBoe/d Warren / Mercer Counties Net Acreage ~12,100 Westmoreland / Clearfield / Centre Net Acreage ~11,000 Butler Operated Current Net Acreage ~62,600 Pro Forma Net Acreage (2) ~269,200 Market Cap (4) Pro Forma Liquidity (5) 2014E Production 2Q'14 Production 3Q'14E Production MY 2014 Proved Reserves (3) MY 2014 PV-10 $800 million $452 million MMcfe/d MMcfe/d MMcfe/d 1,057.8 Bcfe $1,041 million % Liquids 38% 2014E Capex (Pre-Shell Acq.) $350 - $365 million 2014E Wells Drilled Net Acreage (1) ~188,700 Liquids-Rich Drilling Locations (2) Butler Marcellus Butler Upper Devonian Moraine East / Butler Acq. Warrior Prospects (1) As of June 30, 2014; acreage does not include certain peripheral non-core acreage (2) Pro forma for Butler Operated Area acquisition Proved Locations (3) See note Page 2 (4) As of August 26, 2013 (5) Pro Forma June 30, 2014 for $325 million high yield issuance and $125 million preferred offering; calculated as cash plus undrawn revolver less $2.0 million of outstanding L/Cs as of June 30, 2014 ~1,266 gross / 964 net 357 gross / 250 net 431 gross / 302 net 241 gross / 241 net 143 gross / 105 net 94 gross / 66 net 4

5 $ MM MMcfe MMcfe/d Track Record of Growth Average Daily Production E Proved Reserves , MY2014 Adjusted EBITDAX $150.0 $100.0 $50.0 $0.0 $134.8 $62.9 $87.7 $22.5 $

6 Recent Developments

7 Average Daily Production (MMcfe/d) New Developments Recent Achievements Butler Operated Area Acquisition Increases Appalachian size by ~207,000 net acres, up ~195% over current ~107,000 net acres Increases drilling inventory by ~241 locations, up ~24% to 1,266 liquids-rich locations ~3 MMcf/d currently producing into sales; ~13 MMcf/d anticipated to be placed into sales in 2015; estimated proved reserves ~21 Bcfe from these wells Q13A 4Q13A 1Q14A 2Q14A 3Q14E Expansion of Processing Capacity in Butler Operated Area Additional processing capacity added with commissioning of Bluestone II facility Increasing total processing capacity to 405 MMcf/d through construction of Bluestone III & IV, which are expected to be commissioned in 4Q15 and 2Q16 Record Second Quarter Production 50% year-over-year growth in production 5% increase in daily liquids production 30% liquids mix Balance Sheet Completed an offering of $325 million of Senior Notes Net proceeds of $318.8 million; used to repay all borrowings under the company s revolving credit facility Completed an offering of $161 million of convertible perpetual preferred stock Net proceeds of $155.5 million; used to fund the Butler Operated Area acquisition Currently, no outstanding borrowings under revolving credit facility Pro forma liquidity (1) for bond offering and convertible preferred offering of $452 million (1) Pro Forma June 30, 2014 for $325 million high yield issuance and $125 million preferred offering; calculated as cash plus undrawn revolver less $2.0 million of outstanding L/Cs as of June 30,

8 Butler Operated Area Acquisition Entered into agreement to purchase ~207,000 net acres in the Butler Operated Area for a purchase price of $120 million Effective date: July 1, 2014 Estimated closing date: September 10, 2014 Highly strategic acquisition with assets located in Rex s core operating area Attractive liquids-rich Marcellus, Upper Devonian and dry gas Utica potential similar to Rex s existing asset base Minimal transitional issues and potential for further optimization of drilling and completion, as well as operational efficiency Operated assets with high working interests Enhances Rex s dominant liquids-rich Appalachian footprint in and around Butler County and positions Rex for attractive future growth opportunities Increases Appalachian size by ~207,000 net acres, up ~195% over Rex s current ~107,000 net acres Acquisition and future bolt-on leasing increases drilling inventory by ~400 gross identified liquids-rich locations (1) (~241 locations at closing), immediately up ~24% to 1,266 locations Manageable term on leasehold position, as ~70% of acreage is either held by operations or has extensions Inventory of production available for sales provides ability to increase cash flows with modest capital investment ~3 MMcf/d currently producing into sales; ~13 MMcf/d anticipated to be placed into sales in 2015 Attractive deal metrics on a per acre and per location basis Provides a platform for future strategic expansion 8

9 Expanding Core Appalachian Position Shell Acreage Acquisition Net Acreage ~207,000 Net Revenue Interest 83% Wells PIS 4 Butler Extension Area Net Acreage ~90,600 Butler Liquids-Rich Net Acreage ~50,000 Moraine East: ~24,000 net acres Western Lawrence Utica Net Acreage ~66,100 Rex Legacy Acreage Net Acreage ~62,600 9

10 Combined Liquid-Rich Locations Summary The Shell acreage acquisition significantly increases Rex's liquid-rich drilling inventory Area Gross Identified Locations % Liquids (2)(3) Proved Locations 94 ~37% Butler County: Marcellus 357 ~42% , ,266 Butler County: Upper Devonian 431 ~40% 800 Ohio Utica Warrior Prospects 143 ~43% Legacy Appalachia (1) 931 ~41% 400 Existing Liquids-Rich Total (Appalachia + Proved) 1,025 ~40% Acquired Marcellus Acquired Upper Devonian Existing Gross Liquids- Rich Locations Acquired Gross Liquids- Rich Locations Pro Forma Gross Liquids- Rich Locations Total Liquids-Rich Locations 1, Proved Locations Butler County: Upper Devonian Butler County: Marcellus Ohio Utica Warrior Prospects Rex also has a substantial inventory of dry-gas drilling locations on its legacy Appalachian acreage, as well as in the ~90,600 net acres of the acquired Butler extension area, and ~197 targeted Utica locations on the ~66,100 net acres in Western Lawrence Utica Planned infill leasing on Rex s existing and acquired acreage is anticipated to increase the inventory reflected above (1) Existing Appalachian drilling locations as of December 31, 2013; see note on Potential Drilling Locations on page 3 (2) Assumes 80% ethane recovery (3) Net liquids after shrink 10

11 Liquids-Rich Moraine East ~50,000 net acres (24,000 inside development area) targeting wet-gas Marcellus and Upper Devonian contiguous to existing position Complementary fit with the legacy Butler acreage position Initial Development Area Attractive, liquids-rich Marcellus and Upper Devonian inventory Geologic review suggests area is comparable to the existing Butler operations Expect similar economics as Butler Operated Area Opportunity to significantly increase inventory / lateral lengths through infill leasing due to the existing contiguous acreage position Near-term development plan: Pipeline to MarkWest s processing facility (potential 3 rd party) Anticipate adding a rig in 1Q 15 Potential to add joint-venture partner Acreage & Inventory Total Net Acres ~50,000 Average Royalty ~17% Bricker Pad Future bolt-on leasing expected to add ~160 additional liquids-rich locations Initial Gross Locations (750 spacing) 241 (1) Marcellus 134 Upper Devonian 107 Targeted Acre Infill Leasing 10,000 Development Plan Well Count

12 Western Lawrence Utica ~66,100 net acres in Western Lawrence Utica targeting the dry-gas Utica, with existing production and strong offset performance Kephart Drilled Patterson Drilled / Producing Twentier Drilled Hufnagel Drilled / Producing Large inventory of attractive dry-gas Utica acreage Position allows efficient development Long laterals; ability to hold up to 4 units with one pad Surrounded by industry activity (Chesapeake to the South and Hilcorp to the North) Existing takeaway provides ability to get gas to sales quickly, including up to ~50 MMcf/d on TGP and ~30 MMcf/d on NFG No processing constraints Potential to add joint venture partner Value Proposition Test resource potential in 2015; plan to drill ~2-3 wells and then evaluate development plan Dry gas optionality based on pricing Emerging resource play in dry gas Utica Acreage & Inventory Total Net Acres ~66,100 Average Royalty ~17% Initial Gross Locations (750 spacing)

13 Execution Plan: Near-Term Development To execute on development plan for acquired acreage, Rex plans to add 1-2 rigs in 2015, focused on core areas 1 Moraine East rig 1 core Butler rig 1 toggle rig (Legacy Butler / Moraine East) 1 top-hole rig For the remainder of 2014, Rex anticipates spending an incremental $10-15 million of capital to complete existing projects in process Rex currently anticipates the 2015 gross capital budget to include $ million of development capital to be allocated to the acquired Shell acreage Current production of ~3 MMcf/d and with modest capital requirements, an additional ~13 MMcf/d is anticipated to be placed into sales in 2015 Potential to bring in partners Potential to monetize other assets to fund drilling program on acquired acreage 13

14 Company Overview

15 Growing Production and Reserves Production Growth (MMcfe/d) Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14E Actual Production Guidance Low Case Production Guidance High Case Proved Reserves Growth (Bcfe) Second Quarter Production Mix MY2014 Oil and NGLs Natural Gas 15

16 Proved Reserves Mid-Year Update (1) PV-10 Growth ($ MM) (2) Proved reserves increased by 24% from YE 2013 (25% increase in proved developed reserves) ~7% reduction in Butler Operated Area D&C costs in 1H 14 Exceeded 3-5% cost reduction target for FY 2014 Most recent 10 wells in Butler Operated Area drilled in average of 15 days $1,200 $1,000 $800 $600 $400 $200 ~20% fewer days than expected $ /30/2014 Proved Reserves by Commodity Proved Reserves Growth (Bcfe) 1,058 Bcfe (1) Rex Energy's estimated proved reserves at June 30, 2014 were prepared by its internal reservoir engineers and have not been prepared or audited by its independent reservoir engineers (2) Based on SEC pricing for the trailing twelve months ended 06/30/14 1 6

17 Butler Operated Area Midstream Capacity Processing Capacity 90 MMcf/d of current processing capacity at MarkWest facilities MarkWest added 120 MMcf/d of total processing capacity in 2Q 2014 Increasing total processing capacity to 405 MMcf/d through construction of Bluestone III & IV; expected to be commissioned in 4Q15 & 2Q16 Map of Butler Area Midstream MWE Bluestone / Sarsen Plants Firm Transportation C3+ Sales Pro forma for acreage acquisition, ~343 MMcf/d of current and future firm transportation for residue gas Sold by MarkWest Propane sold into local market MWE Ethane Line EPD ATEX Pipeline Mariner West Pipeline REXX Operated Area Dominion Line Mariner East Pipeline Ethane Sales Two outlets beginning 2Q 2014 for ethane sales Enterprise Product Partners ATEX pipeline NOVA Chemicals Mariner West pipeline Source: Publicly available press releases or presentations Existing REXX Acreage Currently in Service Under Construction 17

18 Utica Midstream Providers Warrior North Acreage dedication to Blue Racer Midstream Processing capacity at Natrium facility (Blue Racer) ~14 MMcf/d of residue gas capacity Map of Utica Midstream REXX Warrior North Acreage Blue Racer East Ohio Pipeline EPD ATEX Line MWE Cadiz Processing Plant MWE Hopedale Fractionator REXX Warrior South Acreage Warrior South Acreage dedication to MarkWest Energy Processing capacity of 20 MMcf/d at Seneca facility ~30 MMcf/d of residue gas capacity MWE Seneca Processing Plant MWE Gas & NGL Line Blue Racer Natrium Plant REXX Acreage Source: Publicly available press releases or presentations 18

19 Firm Transportation Butler, PA Texas Gas Transmission Louisiana Access Project Lebanon, OH Receipt Point: Lebanon, OH Delivery Points: Gulf South-Bosco Perryville, LA Pipelines Accessed: DTI, TETCO, REX Rex Energy Capacity: 100,000 MMBtu/d Dominion Transmission Inc. Lebanon West II Receipt Point: TL -400 Bluestone Plants in Butler, PA Delivery Points: Lebanon, OH Pipelines Accessed: DTI, TETCO, REX Rex Energy Capacity: 130,000 MMBtu/d Perryville, LA 19

20 Non-Proven Resource Potential (1) Over 1,200 pro forma gross liquids-rich drilling locations as of December 31, 2013 based on 750 foot spacing in the Appalachian Basin assets (2) Area Gross Identified Locations (2) Net Identified Locations (2) EUR (1)(3)(4) Net Resource Potential (4)(6) % Liquids (4)(7) Butler Operated Area Marcellus ~9.7 Bcfe 1.9 Tcfe ~42% Butler Operated Area Upper Devonian ~8.3 Bcfe (5) 1.9 Tcfe ~40% Ohio Utica- Warrior North ~7.2 Bcfe 0.8 Tcfe ~45% Ohio Utica Warrior South ~12.0 Bcfe 0.3 Tcfe ~37% Total Appalachia N/A 4.9 Tcfe ~41% Proved Locations N/A 0.8 Tcfe (8) 37% Total Legacy 1, N/A 5.7 Tcfe ~40% Moraine East Pro Forma Total 1, N/A N/A N/A Marcellus Upper Devonian Warrior North Warrior South Total Unproven Resource Potential 1.1 6/30/2014 Proved Reserves (1) See note on Hydrocarbon Volumes on page 3 (2) See Note on Potential Drilling Locations on page 3 (3) Assumes 4,000 lateral in Butler and 5,000 lateral in Ohio (4) Assumes 80% ethane recovery (5) 12/31/2013 PUD estimate; Drushel 6HD & Gilliland 11HB EURs assuming 80% ethane recovery averaged 9.75 Bcfe (6) Net resource potential after royalties and on-operated interests (7) Net liquids afer shrink (8) Represents proved reserves rather than net resource potential 20

21 FY2014 Capital Budget Program / Guidance FY 2014 Capital Budget $ in Millions Appalachian Basin Drilling & Completion $300 - $310 Appalachian Basin Facilities, HSE & Equipment $10 Illinois Basin Drilling & Completion $30 - $35 Illinois Basin Drilling & Completion $10 Total 2014 Capital Budget $350 - $365 (1) Budget Allocation FY2014 Budget Highlights 33.0% 2.0% 11.0% ~ 98% of 2014 budget directed towards liquids-rich assets ~ 87% of 2014 budget allocated to liquids-rich development of Butler Operated Area and Ohio Utica Warrior Prospects Drilling program consists of three full-time drilling rigs in the Appalachian Basin Drill gross operated wells in the Appalachian Basin Complete gross operated wells in the Appalachian Basin Does not include capital allocated to Butler Operated Area acquisition 54.0% IL Conventional Butler Ohio WPX Non Operated 3Q14 Guidance FY2014 Guidance Avg. Daily Production MMcfe/d MMcfe/d LOE $ $26.5 million $93 - $98 million Cash G&A $8.5 - $10.0 million $35 - $38 million (1) Excludes leasing, capitalized interest and Keystone Clearwater 21

22 Detailed Hedge Position (1) Natural Gas (2) Oil & Condensate (3) NGLS Swaps Volume (MMBtu/d) 28,431 9,863 Volume (Bbls/d) 1, Volume (Bbls/d) 2, % Hedged 26% 9% % Hedged 30% 2% % Hedged 61% 16% Price ($/MMBtu) $4.11 $4.13 Price ($/Bbl) $97.79 $95.76 Price ($/Bbl) $57.12 $44.52 Natural Gas Oil & Condensate Collars Volume (MMBtu/d) 45,098 22,192 Volume (Bbls/d) 1, % Hedged 42% 21% % Hedged 47% 12% Ceiling Price ($/MMBtu) $4.67 $4.68 Ceiling Price ($/Bbl) $ $ Floor Price ($/MMBtu) $4.12 $4.21 Floor Price ($/Bbl) $89.38 $90.25 Basis Differential Hedges Dominion South Point Volume (MMBtu/d) 16,340 3,288 % Hedged 15% 3% Price ($/MMBtu) ($0.37) ($0.56) 2014 NGL Breakout Propane Butane IsoButane C5+ Volume (Bbls/d) 1, % Hedged 67% 26% 52% 73% Price ($/Bbls) $45.36 $55.86 $56.28 $89.46 Oil & Condensate Avg. Floor: $ % Avg. Floor: $ % Natural Gas Avg. Floor: $ % Avg. Floor: $ % NGLs Avg. Floor: $ % Avg. Floor: $ % 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% (1) Hedging position as of 8/25/2014; percent hedged based on mid-point of FY production guidance (2)Includes 18.1 Bcf hedged with an average short put of $3.54 (3) Includes 495,000 Bbls hedged with an average short put of $

23 Marcellus: Liquids-Rich Butler Operated Area Butler Operated Area Marcellus (1) Three-Well L&L Pad Three-Well Shipley Pad: ~ 8.2 MMcfe/d 46% Liquids Six-Well Michael Pad: Stacked Lateral Pad Recent Developments Increasing total processing capacity to 405 MMcf/d through construction of Bluestone III and Bluestone IV, which are expected to be commissioned in 4Q15 and 2Q16 Added 130 Mmbtu/d of firm transportation accessing new markets and premium pricing Midwest and Gulf Coast markets Three-Well Bame Pad Lynn N&S 3H, 5H 6.9 MMcfe/d 47% Liquids Acreage & Inventory (4) Total Net Acres ~ 62,600 Pro Forma Net Acres ~ 269,200 Average Working Interest ~70% Three-Well Schilling Pad Pro Forma Working Interest ~93% Gross / Net Identified Potential Drilling Locations (3) 357 / 250 Pro Forma Gross / Net Potential Drilling Locations (3) 491 / 384 Current Well Spacing (Lateral Feet) 750 Baillie Trust Pad (2) 6.0 MMcfe/d 53% Liquids Kennedy 1H, 2H 6.5 MMcfe/d Ferree 1H, 2H, 5H, 6H: Stacked Lateral Pad Rigs 2014 Drilling Plan 2 (w/ Upper Devonian) Pads in progress Wells Drilled Pads completed Wells Completed (1) All production results are on a per well basis (2) Results include wells targeting both Marcellus and Upper Devonian (3) See note on Potential Drilling Locations on page 3 (4) Pro Forma for Butler Operated Area acquisition Wells Placed into Sales Wells Awaiting Completion

24 Upper Devonian: Liquids-Rich Butler Operated Area Perry 1HD 5.3 MMcfe/d 55% Liquids Butler Operated Area Upper Devonian (1) Burgh 2HD 4.5 MMcfe/d 53% Liquids Gilliland 11HB 4.2 Mmcfe/d 48% Liquids 6-Well Michael Pad Stacked Lateral Pad Recent Developments Completed five-well Ferree pad - second planned stacked Upper Devonian Burkett/Marcellus pad Expect to be placed into sales in 3Q14 Third planned test Six-well Michael pad, testing multiple stacked Upper Devonian Burkett/Marcellus laterals Continuing to analyze results of Baillie Trust pad No interference noted to date Stebbins 2H 5.5 MMcfe/d 48% Liquids Acreage & Inventory (4) Total Net Acres ~ 54,600 Pro Forma Total Net Acres ~269,200 Average Working Interest ~70% Pro Forma Average Working Interest ~93% Gross / Net Identified Potential Drilling Locations (3) 431 / 302 Pro Forma Gross / Net Potential Drilling Locations (3) 538 / 409 Baillie Trust Pad (2) 6.0 MMcfe/d 53% Liquids Drushel 6HD 7.3 MMcfe/d 49% Liquids Ferree 4HB Stacked Lateral Pad Current Well Spacing (Lateral Feet) Drilling Plan Rigs 2 (w/ Upper Devonian) Pads in progress Wells Drilled 1 3 Pads completed Wells Completed 1 (1) All production results are on a per well basis (2) Results include wells targeting both Marcellus and Upper Devonian (3) See note on Potential Drilling Locations on page 3 (4) Pro Forma for Butler Operated Area acquisition Wells Placed into Sales 1 Wells Awaiting Completion

25 Butler Operated Area Dry Gas Utica Butler Operated Area Dry Gas Utica Cheeseman 1H 5.3 MMcfe/d 30-Day Test Rate Recent Developments Rex Energy has drilled two Butler Operated Area dry-gas Utica wells Cheeseman 1H completed and placed into sales Hufnagel completed and placed into sales Over 100+ Utica locations in the Butler Operated Area; pro forma for acreage acquisition, over 300+ Utica locations Hufnagel Well ~ 3,000 Lateral Adams Well Acreage & Inventory (1) Total Net Acres ~62,600 Pro Forma Total Net Acres ~269,200 Average Working Interest ~70% Pro Forma Average Working Interest ~93% Gross / Net Identified Potential Drilling Locations (1) 116 / 81 Pro Forma Gross / Net Potential Drilling Locations (1) 313 / 278 Current Well Spacing (Lateral Feet) 750 (1) Pro Forma for Butler Operated Area acquisition 25

26 Production Rate (Mcfe/d) IRR (%) Marcellus Economics (1) 6,000 ~ 9.7 Bcfe EUR: 80% Ethane Recovery (2) % 5, % 40% Strip Pricing (4) 4, % 30% Strip Pricing (3) % 3, % 2, % $3.50 $4.00 $4.50 $5.00 Year-End 2013 IRR Mid-Year 2014 IRR 1, Production Month (5) ~ 9.7 Bcfe EUR - YE 2013 ~ 9.7 Bcfe EUR - MY 2014 Cum. Production - YE 2013 Cum. Production - MY Year-End 2013 Well Costs Drill & Complete: ~ $5.9 million Oil: $95.00 Lateral Length: 4,000 feet C3+: $55.00 Mid-Year 2014 Well Costs (1) See note on Hydrocarbon Volumes on page 2 (2) ~ 8.9 Bcfe 55% ethane recovery (3) Strip pricing as of 12/31/2013 (4) Strip pricing as of 6/30/2014 (5) MY 2014 EUR includes increase of ~2% to terminal decline rate; this results in a substantially similar 6/30/2014 as compared to 12/31/2013 Drill & Complete: ~ $5.5 million Oil: $95.00 Year-End 2013 Pricing Assumptions Ethane: ~ $0.30 / gallon Lateral Length: 4,000 feet C3+: $55.00 Nat. Gas Differential: ~ ($0.20) Mid-Year 2014 Pricing Assumptions Ethane: ~ $0.30 / gallon Nat. Gas Differential: ~ ($0.50) 26

27 Wet Gas Upside $

28 Value Per Mcfe Butler Price Realization Comparisons $6.00 $5.00 ~$4.75 / Mcfe ~$5.00 / Mcfe $4.00 ~ $50 / bbl ~$4.25 / Mcfe ~ $56 / bbl $3.00 $2.00 $1.00 $0.00 ~ $3.80 / Mcf ~ $56 / bbl ~ $3.10 / Mcf 2013 Average 2H 2014 Strip FY 2014 Gas NGL Ethane Basis Hedges ~ $4.50 NYMEX ~ ($1.40) Basis Differential ~ $3.90/ Mcf ~ $4.50 NYMEX ~ ($0.60) Basis Differential 28

29 Efficiently Increasing Marcellus EUR (1) Improving Well Design in Butler County Ethane Uplift (3) Ethane Uplift (4) 4.0 Bcfe EUR 5.3 Bcfe EUR ~7.0 Bcfe EUR ~9.7 Bcfe EUR (80% ethane recovery) ~8.9 Bcfe EUR (55% ethane recovery) ~9.7 Bcfe EUR (80% ethane recovery) ~8.9 Bcfe EUR (55% ethane recovery) Year-End 2010 (12/31/10 Reserve Report) Year-End 2011 (12/31/11 Reserve Report) Year-End 2012 (12/31/12 Reserve Report) Pro Forma (12/31/12 Reserve Report) 12/31/13 (12/31/13 Reserve Report) Completion Conventional Frac Conventional Frac Super-Frac (5) Super-Frac (5) Super-Frac (5) Gross Average 30 Day Wellhead IP 2,070 2,235 3,142 3,142 3,175 First Year Decline (2) 66% 66% 54% 54% 50% Lateral Length 3,500 3,500 4,000 4,000 4,000 Stages All-in Costs ~$4.7 million ~$5.3 million ~$6.5 million ~$6.5 million ~$5.9 million (1) See note on Hyrdocarbon Volumes on page 2 (2) NSAI reserve reports (type curve declines) (3) Estimated impact to 7.0 Bcfe EUR well after giving effect to 2014 ethane and transportation agreements (4) Estimated impact after giving effect to 2014 ethane and transportation agreements (5) Super-Frac refers to Rex s reduced cluster spacing completion design As of 6/30/2014, all-in cost is ~$5.5 million 29

30 Pads Number of Wells Operational Efficiencies Butler Op. Area Avg. Lateral Length: ~ 4,000 ft Avg. Lateral Length: ~ 5,100 ft Butler Operated Area Average Lateral Length < 3,000' 3,000' - 4,000' 4,000' - 5,000' 5,000' - 6,000' 6,000' - 7,000' > 7,000' wells per pad 2.5 wells per pad Butler Operated Area Wells Per Pad well pad 2-well pad 3-well pad 4-6+ well pad Avg. Wells Per Pad 2014 Avg. Wells Per Pad 30

31 Butler Area Focus Drives Value Creation Expanding Processing Capacity Increasing total processing capacity to 405 MMcf/d through Bluestone III & Bluestone IV Bluestone III & Bluestone IV expected to be commissioned in 4Q15 and 2Q16 Ethane takeaway started in 2Q 14 Securing Firm Transportation 213 MMcf/d of current firm transportation Added 130 MMcf/d of firm transportation to Midwest and Gulf Additional gas takeaway opportunities available Reducing Drilling Costs $6.5 million for 4,000 lateral at 12/31/12 $5.9 million for a 4,000 lateral budgeted in 2014 (down ~10%) $5.5 million based on MY 14 operations and realized cost reductions Additional potential cost reduction opportunities (e.g. pad drilling) Drivers of Butler Area Economies of Scale Accelerating Development More than doubled the 2013 wells drilled with wells being drilled in 2014 Running 2 full time rigs in 2014; anticipate adding 2 rigs in 2015 on acquired acreage Building Operational Scale Contiguous acreage blocks creates a dominant position and enables attractive lease acquisition cost Extending lateral lengths and increasing well density on pads Per unit production costs decreasing Developing Multiple Formations Currently ~93 wells producing from 3 formations ~1,200 pro forma potential liquids-rich locations at 750 spacing Additional dry gas opportunities 31

32 Ohio Utica: Warrior Prospects G. Graham 1H Warrior North Prospect Brace 1H Brace West 1H, 2H Ocel 1H, 2H, 3H Recent Developments Completed six-well Grunder pad in Warrior North Expected to be placed into sales in 3Q14 Tested 500 & 600 foot spacing Completed three-well Jenkins pad in Warrior North Avg. lateral length of ~ 5,350 feet Expected to be placed into sales in 3Q14 Drilling six-well J. Hall pad in Warrior South Avg. lateral length of ~ 5,400 feet Testing 650 foot downspacing Six-Well Grunder Pad Avg. Lateral Length of ~4,800 feet Guernsey Five-Well J. Anderson Pad Pads in progress Noble Pads completed Warrior South Prospect Three-Well Jenkins Pad Avg. Lateral Length of ~5,350 feet Six-Well J. Hall Pad Belmont Three-Well Guernsey/Noble Pad Acreage & Inventory Total Net Acres ~ 21,300 Warrior North Average Working Interest ~ 100% Warrior South Average Working Interest ~ 63% Gross / Net Identified Potential Drilling Locations 143 / 105 Current Assumed Wells Spacing (Lateral Feet) Drilling Plan Rigs 1 Wells Drilled 12 Wells Completed 18 Wells Placed into Sales Wells Awaiting Completion -- 32

33 Condensate Yield (Bbls/ 1 MMcf) Production Rate (Boe/d) Cumulative Production (MMboe) Warrior North Prospect Economics (1) 1,400 1,200 1, Assumes 55% ethane recovery % 50% 45% 40% Strip Pricing (2) Strip Pricing (2) Production Month 1.2 MMboe EUR - YE Reserve Case Cum. Production 35% 30% 25% Strip Pricing (2) After 18 months, Brace 1H is at ~ 40 Bbls / 1 MMcf Production Month ~ 1.2 MMboe EUR - YE Reserve Case Improved Condensate Yield YE Reserve Case EUR: 35% NGLs / 54% Natural Gas / 11% Condensate EUR w/ Potential Condensate Yield: 34% NGLs / 51% Natural Gas / 15% Condensate 20% 15% 10% $3.50 $4.00 $4.50 $5.00 Well Costs ~ 1.0 MMboe EUR - YE Reserve Case ~ 1.2 MMboe EUR - YE Reserve Case ~ 1.2 MMboe EUR at Improved Condensate Yield Pricing Assumptions 24-Hour IP Rate Assumptions - ~1.2 Mmboe YE Reserve Case Drill & Complete: $7.8 MM Oil: $95.00 Wellhead Gas: ~ 4.6 MMcf/d Lateral Length: 5,000 ft. C3+: $55.00 Condensate: ~ 300 Bbls/d Ethane: $0.30 / gallon NGLs: ~ 500 Bbls/d (1) See note on Hydrocarbon Volumes on page 2 (2) Strip pricing as of 12/31/

34 Condensate Yield (Bbls/ 1 MMcf) IRR (%) Production Rate (Boe/d) Cumulative Production (MMboe) Warrior South Prospect Economics (1) 2,500 2,000 1,500 1, Assumes 55% ethane recovery Production Month ~ 2.0 MMboe EUR - YE Reserve Case Cum. Production 80% 70% 60% 50% 40% Strip Pricing Strip Pricing Production Month ~ 2.0 MMboe EUR - YE Reserve Case Improved Condensate Yield 30% Strip Pricing 20% $3.50 $4.00 $4.50 $5.00 Well Costs Henry Hub Natural Gas Prices IRR at ~ 1.7 MMboe EUR - YE Reserve Case IRR at ~ 2.0 MMboe EUR - YE Reserve Case ~ 2.0 MMboe EUR at Improved Condensate Yield Pricing Assumptions 24-Hour IP Rate Assumptions - ~1.2 Mmboe YE Reserve Case Drill & Complete: $8.5 MM Oil: $95.00 Wellhead Gas: ~ 7.8 MMcf/d Lateral Length: 5,000 ft. C3+: $55.00 Condensate: ~ 300 Bbls/d YE Reserve Case EUR: 35% NGLs / 63% Natural Gas / 2% Condensate EUR w/ Potential Condensate Yield: 34% NGLs / 61% Natural Gas / 5% Condensate Ethane: $0.30 / gallon NGLs: ~ 700 Bbls/d (1) See note on Hydrocarbon Volumes on page 2 34

35 Illinois Basin Conventional Oil Illinois Basin Lawrence Field / Gibson & Posey Counties Lawrence Lawrence Field Recent Developments Gross production per day across whole field: ~ 2,800 bbls/d Premium pricing NYMEX minus ~ $2.50 Selling into local markets Additional upside from ASP Project Illinois Basin Overview Total Net Acres ~81,700 Average Working Interest 100% 2014 Drilling Plan Rigs ~ 1 Gibson Gibson / Posey Counties Wells Drilled 9 11 Wells Completed (1) Wells Placed into Sales 9-11 Wells Awaiting Completion -- Posey (1) Includes 20 re-fracs 35

36 Marcellus Non Operated Overview Non Operated Westmoreland County, PA Non-Operated Overview Sizable acreage position in Westmoreland, Clearfield and Centre Counties, PA ~ 28,300 gross / ~ 11,000 net Combined average production for a recent 5-day period 61.0 MMcf/d 7.0 gross MMcf/d firm capacity with interruptible takeaway into Columbia gas line in Clearfield/Centre Counties Acreage (2) Non Operated Clearfield / Centre Counties Total Net Acres ~11,000 Average Working Interest 40% 2014 Drilling Plan (3) Wells Drilled 1 Wells Completed 6 Wells Placed into Sales 6 Wells Awaiting Completion -- (1) Includes non-operated area acreage only (2) As of June 30, 2014 (3) Well information in gross 36

37 Appendix

38 Butler Operated Area Stacked Pays UPPER DEVONIAN SHALES MARCELLUS RHINESTREET SHALE Mixed Organic & Non-organic Shale MIDDLESEX SHALE Mixed Organic & Non-organic Shale GENESEE SHALE Mixed Organic & Non-organic Shale BURKETT SHALE - Organic Black Shale TULLY LIMESTONE HAMILTON SHALE Mixed Organic & Non-organic Shale MARCELLUS SHALE Organic Black Shale ONONDAGA LIMESTONE Reservoir thick (4,500 to 4,800 deep) Reservoir thick (4,700 to 5,500 deep) Reservoir thick (4,900 to 5,700 deep) UTICA UTICA SHALE POINT PLEASANT Reservoir thick (9,000 to 11,000 deep) TRENTON LIMESTONE 38

39 Baillie Trust Pad Stacked Laterals 750 spacing spacing 600 spacing Stacked Laterals Testing Spacing Tested both Marcellus and Upper Devonian Burkett through use of stacked laterals Utilizing microseismic testing to demonstrate expected lack of communication between formations Providing cost efficiencies Tested 600-foot spacing vs. 750-foot spacing on most recent Marcellus units Current inventory of 431 Upper Devonian Burkett locations assumes 750-foot spacing Current indications suggest downspacing is successful; Rex to continue monitoring production/pressure profiles Landing Zone Tested different landing zones in two of the four Marcellus wells 39