Natural Gas - Rex Energy

Rex Energy
Corporate Presentation
October 2012
Responsible Development of America’s Energy Resources
Rex Energy Corporation | 476 Rolling Ridge Drive | State College, PA 16801
P: (814) 278-7267 | F: (814) 278-7286
E: [email protected]
www.rexenergy.com
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
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
Rex Overview
•
•
•
•
Quality of Assets
• Focused Operations – Appalachia Basin and Illinois Basin
• Butler Operated – 3 Drilling Horizons, 4th Potential Horizon
• Marcellus, Upper Devonian and Utica
• Ohio Utica – Oil & Liquids Rich
• Illinois Basin – ASP and Conventional Oil Drilling
• Industry leading midstream partner
Sustained High Quality Growth
• Estimated 2012 Production Growth of 73%
• 3-Year CAGR of 61%
• Over 1,000 Liquids Rich Locations
Increased Liquids Production from Ohio Utica and Illinois Basin –
Estimated Liquids Mix > 30% at year-end 2012
• 2012E Liquids Production Growth - ~26%
Strong Balance Sheet
• Over $200 million of liquidity at year-end 2012
• 64% of 2012 Natural Gas Production Hedged
• 84% of 2013 Natural Gas Production Hedged
4
Solid Financial Position
Balance Sheet
• $15.6 million in cash
• $130 million debt with $260 million available
• $80 million of debt on senior credit facility with $210 million available
• $50 million of debt on second lien facility with $50 million available
• Borrowing base increased to $290 million from $265 million in September 2012
• No debt maturity until 2015 (Senior Credit Facility) and 2016 (Second Lien Facility)
Liquidity Position
• Over $200 million of liquidity at year-end 2012
• Liquidity position positions the company well for 2013 capital plan
Excellent Hedge Position
• For 2012, approximately 64% of natural gas production hedged with $4.37 floor; 53% of propane hedged at $1.03
per gallon ($43.26 / bbls)
• For 2013, approximately 84% of natural gas production hedged with $4.32 floor; 56% of propane hedged at $1.03
per gallon ($43.26 / bbls)
5
Strong Balance Sheet
Liquidity Sources
($ millions)
Cash as of 6/30/2012
$15.6
6M12 Op. Cash Flow – Analyst Consensus
$42.0
Subtotal
$57.6
Availability on senior credit facility1
$210.0
Availability on second lien facility
$50.0
Subtotal
$260.0
Total Sources of Liquidity
$317.6
Remaining 2012 capital expenditure budget2
$97.1
Liquidity as of January 1, 20133
$220.5
1. Debt levels of 6/30/2012
2. 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
6
Sustained High Quality Growth
Average Daily Production (Mcfe)
80,000
73%
70,000
60,000
50,000
92%
40,000
30,000
20,000
3%
26%
10,000
0
2009 (A)
2011 (A)1
2010 (A)
Natural Gas
NGL & Condensate
2012 Revised
Midcase Guidance (E)
Oil
1. Excludes production from discontinued operations
7
Current Hedging Summary
Crude Oil
Current Production Hedged
% of Current
with Floor
% of Current
with Ceiling
Avg. Floor
Price
Avg. Ceiling
Price
2012
79%
79%
$ 68.39
$ 111.08
2013
73%
73%
$ 72.44
$ 112.56
2014(1)
27%
27%
$ 80.00
$ 106.25
80%
Commodity % Hedged
70%
60%
Natural Gas
50%
% of Current
with Floor
% of Current
with Ceiling
Avg. Floor
Price
Avg. Ceiling
Price
40%
2012(1)
64%
64%
$ 4.37
$ 4.81
30%
2013(1)
84%
69%
$ 4.32
$ 4.58
2014
28%
28%
$ 3.49
$ 4.13
20%
Natural Gas Liquids/Propane
10%
% of
Propane
% of
Liquids
Price per
Gallon
Price per
Barrel
2012
53%
26%
$ 1.03
$43.26
2013
56%
28%
$ 1.03
$43.26
0%
2012
2013
Commodity
Oil
Natural Gas
Propane
•
1.
Portions of production hedged with put spreads and collar contracts with short puts. See
Appendix for more information
Percentage hedged based on 3rd Quarter 2012 mid-case
guidance with standard decline
8
Selected Financial Data
2011 F&D Costs - Drill-Bit
2011 LOE / Mcfe - Appalachia
G&A / Mcfe – First Six Months of 2012
Debt-to-Capitalization
• Peer group: AREX, COG, CRZO, EQT, GPOR, GST, KOG, MHR, PDCE, PVA, RRC
9
Quality Assets with Rich Resource Potential
Warrior Prospects – Utica Shale
133.6 MMBOE Resource Potential
~17,800 Net Acres
Illinois Basin
31,500 MBbls Resource Potential
~ 23,525 Gross (23,495 Net) Acres
Westmoreland / Clearfield
Non-Operated
~52,400 gross (18,500 net) acres
Butler Operated Marcellus
1.5 Tcfe Resource Potential w/o Ethane
2.0 Tcfe Resource Potential w/ Ethane
~141,000 Gross (70,400 Net) Acres
Butler Operated Upper Devonian
1.2 Tcfe Resource Potential w/o Ethane
1.6 Tcfe Resource Potential w/Ethane
~ 69,000 Gross (46,000 Net) Acres
Total Liquids Rich Resource Potential
~3.7 Tcfe / ~614 MMBOE (Excluding Ethane Recoveries)
~4.6 Tcfe / ~765 MMBOE (Full Ethane Recoveries)
10
Butler Operated Area
Butler Operated Area
Burgh; Upper
Devonian Test
Location
Pallack Pad
Location
• Consolidated acreage position of ~69,000 gross
(~46,000 net) acres (Butler, Beaver and Lawrence Counties)
• Access to three producing horizons, fourth potential horizon:
Plesniak Pad
Location
•
Carson Pad; 2
wells completed
Grubbs; SuperRich Marcellus Test
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 2012
• 21 wells drilled awaiting completion1
“Super Frac” design providing encouraging results
Leasing program focused on increasing well counts
•
•
•
Gilliland #11HB –
Burkett Well
YTD Butler County Drilling Program Well Counts2
Drushel #3:
Super-Frac
Behm Pad; 3
wells completed
Standard Fracture Stimulation
Wells Drilled
Fracture
Stimulated
Placed in
Service
Awaiting
Completion
13
16
18
14
Super-Frac Stimulation
1.
2.
Includes two wells completed awaiting pipeline at the end of 2011
Includes one Utica Shale well in Butler County
2012 Butler County Drilling Program Well Counts2
Wells Drilled
Fracture
Stimulated
Placed in
Service
Awaiting
Completion
20
19
19
18
11
MarkWest Effect on NGL Price Realizations
• NGL Price assumption of 40% of $90.00 NYMEX WTI
$90.00 NYMEX WTI
$54.00 / Bbls
$54.00 / Bbls
Pipeline
Trucks / Rail
($12.18/bbl)
Transportation
Cost
($2.52/bbls)
Transportation
Cost
~25%
$41.82 / Bbls
$51.48 / Bbls
Current
2014
12
Butler County Marcellus Economics
Butler Area (Operated) Assumptions
1.
2.
3.
4.
See note on “Hydrocarbon Volumes” on page 3
Assumption used for “Current Ethane Recovery” projections of 1.64 gallons per Mcf
Assumption used for “Full Ethane Recovery” projections of 4.5 gallons per Mcf
Curve reflects natural gas equivalent pricing for ethane
Gas Production Rate (Mcfe/d)
Well costs of $5.3 million per well
Lateral length of 3,500 ft.
30-Day average rate of 3.8 MMcfe/d
Reference Oil Price: $90.00
EUR of 5.3 Bcfe per well1
• EUR range increases 20% over 2010 EUR
with only 13% increase in well cost
• NGL yield with current ethane recovery of 1.64
gallons per Mcf (39 Bbls per MMcf)
• Butler Area type curve based on current ethane
recovery and NGL yield
• NGL yield with full ethane recovery of
approximately 4.5 gallons per Mcf (107 Bbls per
MMcf)
• Full ethane recovery increases EUR
to ~7.0 Bcfe per well
• Extension of Y-grade pipeline will reduce
transportation costs by $0.23 per gallon by
first quarter of 2014
•
•
•
•
•
Butler County Wet Gas Type Curve
6,000
5,000
4,000
3,000
2,000
1,000
0
0
10
20
30
40
Production Month
Current Ethane Recovery
50
60
Full Ethane Recovery
Before Tax IRR
60%
IRR at Current
Strip Prices
50%
40%
30%
20%
10%
0%
$3.00
$3.50
$4.00
IRR - Current Ethane Recovery
$4.50
$5.00
2
IRR - Full Ethane Recovery & Transportation Reduction
3,4
13
Marcellus “Super Frac” Type-Curve Results
2011 “Super Frac” Results:
•
•
•
•
Two “Super Frac” Jobs Performed
Average Lateral Length: 3,450’
Average Frac Stages Performed: 24
Both wells on production for over one year
~ 8.0 BFCE Type Curve
Decline Yr. 1: 37%
2012 “Super Frac” Results:
•
•
•
•
•
Six “Super Frac” Jobs Performed
Average Lateral Length: 3,800’
Average Frac Stages Performed: 24
Two wells on production for ~ 90 days
Four wells on production for ~ 30 days
“Super Frac”: Type-Curve Considerations as
compared to YE 2011- 5.3 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: +7MM # (+40%)
•
Well Cost: $6.2MM to $6.4MM (+17% to +21%)
•
EUR: ~8 BCFE *(+51%)
•
EUR: ~11.0 BCFE** (+51%) w/ ethane recovery
*No Ethane recovery ~24% Liquids ** Full Ethane recovery ~45% Liquids
14
Utica Shale Overview
~ 106,200 gross (~72,200 net) acres
• Ohio Warrior Prospect 15,400 acres
• Brace #1H Ohio Utica Well – 1.1 Mboe/d 24-hour IP
rate; 1.0 Mboe/d 5-day rate
• Ohio Warrior South Prospect – ~ 5,600 gross (3,100 net)
acres – Three wells drilled in 2012
• Targeting 20,000 net acres in Warrior Prospects
• 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 120day rate
• Warren & Mercer Counties – ~ 16,200 gross (7,700 net)
acres
2012 Utica Shale Drilling Program Well Counts1
Wells Drilled
Fracture
Stimulated
Placed in
Service
Awaiting
Completion
5
2
1
3
2013 Utica Shale Drilling Program Well Counts1
Wells Drilled
Fracture
Stimulated
Placed in
Service
Awaiting
Completion
12
9
9
3
1. Includes one PA-Utica well
15
Ohio Utica – Warrior North Prospect
• Exceeded +15,000 acres of leasehold in
Warrior North
• Drilling operations began in 2Q-2012
• Brace #1H Ohio Utica well – 1.1 Mboe/d 24-hour
sales rate; 1.0 Mboe/d 5-day average sales rate
• Encountered over 135’ of Point Pleasant and
143’ of Utica pay zone. Well SI for 60 days
oil / condensate / liquids-rich gas zone
• Over 100 net drilling locations in Warrior North
Prospect
• Wells Drilled
Brace #1H Results (Boe/d)
Natural
Gas
Condensate
24-hour
sales rate
336
291
5-day
sales rate
306
273
NGLs
467
429
Total
(Full
Ethane)
% of
Liquids
Total
(Ethane
Rejection)
1,094
69%
911
1,008
70%
839
REXX Brace 1H: 291 Bbls
of condensate per day; 3.1
MMcf/d (wellhead); 467
bbls of NGLs/d – 1.1
Mboe/d - Into Sales
CHK Coniglio 6H:
1.1 Mboe/d – Peak Rate
CHK Mangun 22-15-5 8H:
1.5 Mboe/d – Peak Rate
EVEP Cairns 5H: 729 bbls of
condensate per day; 2.2
MMcf/d; 587 bbls of NGLs/d –
1.7 Mboe/d - Peak Rate
CHK Shaw 20-14-5H:
1.4 Mboe/d – Peak
Rate
CHK Neider 10-14-5 3H:
1.6 Mboe/d – Peak Rate
CHK Burgett #7-15-6-8H:
1.2 Mboe/d – Peak Rate
CHK Snoddy 11-13-5 #6H:
1.3 Mboe/d – Peak Rate
CHK Bailey 35-12-4 3H:
1.4 Mboe/d – Peak Rate
CHK Buell 10-11-5 8H:
3.0 Mboe/d – Located 10
miles south in Harrison
County – Peak Rate
• Green dots indicate sites of potential wells
1.
See note on “Potential Drilling Locations” on page 3
16
Ohio Utica – Warrior South Prospect
~ 5,600 gross (3,100 net)
GPOR – Boy Scout 1-33H
Test Rate of 1,560 bbls of
condensate/day, 7.1
Mmcf/day, 1,008 bbls of
NGLs/day – assumes full
ethane recovery
acres1
• Located in Guernsey, Noble and Belmont
Counties
• Acreage within liquids rich window of the
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 –
Groh 1-12H
Utica Shale
GPOR – Shugert 1-1H
• Drilling second of three planned wells
• Currently planning to frac one well in 4Q
APC - Spencer A-34
239 BOE/d
• Joint Development Agreement with MFC
Drilling and ABARTA Oil & Gas Co.
• 21 Potential net drilling
REXX –Three Well
Pad
Guernsey#1H
Noble#1H
Guernsey #2H
locations2
• Expect to secure wet gas transporting
capacity for Warrior South development
• Actively leasing in the area
Proposed MWE
Liquids Line
APC – Brookfield A-3H
600 BOE/d
Antero – Miley 5-H
PDCE –
Palmer 44-20 Well
1.
2.
Subject to terms and conditions of farm-in agreement
See note on “Potential Drilling Locations” on page 3
APC – Sharon A-1H
626 BOE/d
17
Illinois Basin Conventional Oil Infill &
Recompletions
Illinois Basin
~ 23,500 gross (~ 23,500 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
• Multiple 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 greater than
250-400 gross BOPD in 4Q
18
Lawrence Field ASP Overview & Update
Perkins-Smith
58 Acres
Middagh Pilot
15 Acres
Griggs
72 Acres
Delta Unit
Delta Impact to Production/Reserves:
• 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
~13,100 gross (13,000 net) acres in Lawrence Field
• Estimated 1 billion barrels of original-oil-in-place (OOIP)
• Field currently produces ~1,600 gross (1,250 net) barrels per day under
waterflood
• Field ASP injection plant completed in 2008
• Capacity design of 72,000 Bbls per day
• Middagh Pilot:
• Production averaged 50.1 gross BOPD in 2Q12 vs. 60.7 gross BOPD in
1Q12
• Current proved reserves booking of 13% of pore volume continues to be
confirmed
• Peak production was seen at 100+ BOPD
• Perkins Smith Unit Pilot Expansion
• ASP injection commenced in June 2012
• Initial project response expected by 2nd quarter of 2013
• Delta Unit Full Scale Commercial Expansion
• 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
19
Upcoming Catalysts
Catalysts
•
Results from first Ohio Utica Shale well – Brace #1H
• 30-day average sales rate
• 24-hour sales rate of 1.1 Mboe/d and 5-day averages sales rate of 1.0 Mboe/d
•
Continued enhancement of the Butler Operated assets
• Increasing EURs with “Super Frac” completion method
• Further testing of the Burkett shale
• Testing the Super Rich Marcellus
• Testing of the Rhinestreet formation
•
Increasing conventional drilling and ASP project activity in the Illinois Basin
•
Strong liquidity position for the remainder of 2012 and into 2013
• Expecting to have approximately $220 million in liquidity at the beginning of 2013
• 64% of 2012E natural gas production hedged
• 89% of 2013E natural gas production hedged
• Any increase to borrowing base would further enhance liquidity
•
2012 liquids exit rate expected to be in excess of 30%
20
Appendix
Responsible Development of America’s Energy Resources
Third Quarter and Full Year 2012 Guidance
Third Quarter
2012
Full Year
2012
Average Daily Production
70.0 – 72.0 MMcfe/d
66.0 – 69.0 MMcfe/d
Lease Operating Expense
$11.0 - $13.0 million
$46.0 – $50.0 million
Cash G&A
$6.0 – $7.0 million
$20.0 – $24.0 million
Capital Expenditures
N/A
$180.0 million
22
2012 Operating Capital Budget
23
Butler Super Rich Wet Gas Stream
Burgh; Upper Devonian
Test Location for
+30% Increased Liquids
FORMATION NAME & DESCRIPTION
UPPER DEVONIAN SHALES
RHINESTREET SHALE
Grubbs; Super Rich
Marcellus Test Location for
+15% Increased Liquids
Plesniak – Super-Frac
Stimulations
Pallack – Super-Frac
Stimulations
Wack; Super Rich
Marcellus Test
Location for
+15% Increased
Liquids
Mixed Organic &
Non-organic Shale
Reservoir 4
MIDDLESEX SHALE
Mixed Organic &
Non-organic Shale
Reservoir 3
GENESEE SHALE
Mixed Organic &
Non-organic Shale
BURKETT SHALE
Organic Black Shale
TULLY LIMESTONE
HAMILTON SHALE
Mixed Organic &
Non-organic Shale
MARCELLUS
Gilliland 11HB Burkett
Super-Rich
+16% Liquids Vs.
Marcellus
~200’ Structurally
Higher Than Marcellus
Carson Pad;
Super Frac
Stimulations
200’ Higher
+16%
Liquids
Reservoir 2
MARCELLUS SHALE
Organic Black Shale
ONONDAGA LIMESTONE
24
Butler Area Utica Shale Resource Potential1
Rex Energy Cheeseman #1H –
5.3 MMcf/d Dry Gas
30-Day Test Rate; 4.1 MMcf/d Dry
Gas 60-day Test Rate; 3.7 MMcf/d
Dry Gas 120-day Test Rate
Hufnagel well
Butler Operated Area: Utica Shale – Dry Gas
Unproved Prospective
Acreage2
~46,100
Net Potential Well Locations3
108
EUR4
4.5 Bcfe
Royalty Burdens
18%
Resource Potential1
398.5 Bcfe
1. See notes on “Forward Looking Statements” and “Hydrocarbon Volumes” on pages 2&3
2. Based on net acreage position excluding acreage from proved developed and undeveloped reserves that the company believes to be prospective
for Utica Shale development. Actual future development of this acreage may vary. See notes on “Forward Looking Statements” and “Hydrocarbon
Volumes” on pages 2&3.
3. See note on “Potential Drilling Locations” on page 3; drilling assumptions based on what the company believes can be drilled economically under
the current commodity price environment
4. Current EUR assumption based on internal estimates using a 4.3 MMcf/d 30-day estimated average production rate; see notes on “Forward
Looking Statements” and “Hydrocarbon Volumes” on pages 2&3
25
Butler Area Midstream & Infrastructure
• Firm transportation of 85.0 gross MMcf/d
Butler Operated Area
• 25.0 gross MMcf/d available March 2012
• Remaining 60.0 gross MMcf/d available January 2013
Cheeseman #1 –
Pipeline tap into NFG
Proposed NGL Gathering Line to
MarkWest Houston Fractionation
Facilities
• Sarsen Plant
• Capacity increased to 40.0 MMcf/d in February 2012 with
commissioning of the Voll compressor station
Voll Compressor Station
• Bluestone Plant
• 50.0 MMcf/d processing capacity design
• Commissioned in May 2012
Sarsen Cryogenic
Processing Plant
• 100 MMcf/d of additional capacity following MarkWest
infrastructure expansion
• Cheeseman #1H Utica Shale well placed into NFG sales
• Expecting ethane sales in first half of 2014
Bluestone Cryogenic
Processing Plant
1. Pipeline route shown for illustrative purposes only. Actual pipeline route, design, construction and
capacity may vary from illustration shown. See note on “Forward Looking Statements” on page 2.
The company can give no assurance that proposed ethane projects will be completed or that
ethane markets will expand as currently projected
26
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
27
Utica/Point Pleasant Potential in Pennsylvania
Rex Energy – Cheeseman 1-H – Butler
County
Note: Utica/Point Pleasant Play in Northeast PA will be different from OH Play
due to changes in rock type
Crawford County, PA Well –
Legacy Well
28
Marcellus Non-Operated Overview
Westmoreland, Clearfield and Centre Counties, PA
•
•
•
•
•
•
Sizeable acreage position with ~52,400 gross (~18,500 net) acres1
34 Wells producing in Westmoreland County
8 Wells producing in Clearfield and Centre Counties
57.0 gross MMcf/d (18.9 Net) June Avg. Daily Production Rate in Westmoreland County
8.6 gross MMcf/d (2.8 Net) June Avg. Daily Production Rate in Clearfield and Centre County
65.6 gross MMcf/d (21.7 Net) Combined June Avg. Daily Production
YTD Non-Operated Drilling Program Updated Well Counts
Wells Drilled
Fracture
Stimulated
Placed in
Service
Awaiting
Completion
5
0
0
9
2012 Non-Operated Drilling Program Updated Well Counts
Wells Drilled
Fracture
Stimulated
Placed in
Service
Awaiting
Completion
5
0
0
9
1. Includes non-operated area acreage only
Clearfield – Centre
County
Non-Operated Area
Westmoreland County
Non-Operated Area
Columbia
Dominion
Equitrans
REX Leasehold
Areas
29
Non-Operated Midstream and Infrastructure
Westmoreland County, PA
• 17.0 gross MMcf/d capacity through Ecker Station tap
into Dominion line
Clearfield – Centre
County
Non-Operated Area
• 35.0 gross MMcf/d capacity through high pressure
delivery system into Peoples line
• 29.0 gross MMcf/d capacity through Salem Beagle
Club station into Equitable gas line
• 81.0 gross MMcf/d total capacity in Westmoreland, PA
Clearfield and Centre Counties, PA
• 7.0 gross MMcf/d firm capacity with interruptible
takeaway into Columbia gas line
Westmoreland County
Non-Operated Area
Columbia
Dominion
Equitrans
REX Leasehold
Areas
30
Westmoreland County Marcellus Economics
Westmoreland County (Non-Operated)
Assumptions
• Well costs of $5.8 million per well
• Lateral length of 3,500 ft.
• EUR of 4.2 Bcf per well
• EUR increase 40% over 2010 EUR with only
23% increase in well cost
• Seven wells in Westmoreland County on the Marco
#1 and National Metals #1 pad producing above
the current type curve
• 150-day cumulative average rate
50% above 4.2 Bcf type curve
• This represents a potential EUR
of ~6.0 Bcf per well
• Reduced cluster spacing (RCS) tests
performed on National Metals wells
• EURs on last 12 wells completed all
exceeding a 6.0 BCFE type curve
Gas Production Rate (Mcfe/d)
Westmoreland County Dry Gas Type Curve
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
0
10
20
30
40
50
Production Month
4.2 Bcf Type Curve
6.0 Bcf Type Curve
60
Before Tax IRR
50%
45%
40%
35%
30%
25%
20%
15%
10%
5%
0%
IRR at Current
Strip Prices
$3.00
$3.50
IRR - 4.2 Bcf Well
$4.00
$4.50
$5.00
IRR - 6.0 Bcf Well
31
ASP Economics
Resource Potential Range Confirmed
• Proved reserve bookings at 13% of pore volume
recovery confirming mid-point resource potential
range of ~31.5 MMBbls (net)
• North and Central Lawrence Units reviewed for
ASP potential in Bridgeport and Cypress
formations by NSAI
• 27 ASP targets identified across both units
combined2
• Estimated 76% of North and Central Lawrence
acreage prospective for ASP flooding, with a
further ~1,900 acres of South Lawrence unit to
undergo further review
Resource Potential: North & Central Lawrence Units1
Low Case
High Case
Bridgeport Sand Pore Volume
182.7 MMbbl
Cypress Sand Pore Volume
128.3 MMbbl
Royalties
22%
Recovery Potential (%PV)
Total ASP Upside Potential (Net)
13%
20%
31.5 MMbbl
48.5 MMbbl
Delta Unit ASP Economics
60
50
• $9MM of Capex in 2012 and $21MM in 2013
• Proved reserve bookings at 13% of Pore Volume
equate to ~20% IRR at $100/Bbl NYMEX prices
• All reserves recovered in first 6 years
• Discounted Return on Investment: ~1.25
• Full-cycle F&D Cost ~$25-$30/Bbl
1.
2.
3.
40
IRR (%)
Delta Unit Conceptual Economics3
30
20
10
0
13
14
15
16
17
18
Pore Volume Recovery %
19
Resource potential and pore volume recovery assumptions based on full development program. Individual ASP unit results may vary significantly. See note on “Hydrocarbon Volumes” on page 3
See note on “Potential ASP Units” on page 3
Based on company estimates and projections to date. See note on “Hydrocarbon Volumes” on page 3
20
32
Liquids Production Ratios
Current Liquids Sales Ratio
Natural
Gasoline
18%
IsoButane
7%
Liquids Sales Ratio With Full Ethane Sales
Iso-Butane
Butane 3%
Ethane
10%
Natural
Gasoline
7%
5%
Propane
18%
Butane
15%
Ethane
67%
Propane
50%
1.64 Gallons per
Wellhead Mcf
4.5 Gallons per
Wellhead Mcf
33
Proved Reserves with Ethane Solution
34
2011 Proved Reserves
35
Rex Energy Liquids-Rich Resource Potential1
Total Liquids-Rich Operating Area
Resource Potential1
Butler Marcellus:
Liquids Rich
Butler Upper Devonian:
Liquids Rich
Warrior Prospect:
Liquids Rich Utica
ASP:
Oil
0
500
1,000
Estimated Resource Potential (Bcfe)
1
1,500
2,000
2,500
Additional Ethane Recoveries 2
MMBOE
Bcfe
Oil & Condensate
67.9
407.6
NGLs
121.6
729.8
Natural Gas
424.4
2,546.4
Total
613.9
3,683.8
Additional Ethane
Recoveries2
150.7
904.0
Total with Additional
Ethane Recoveries2
764.6
4,587.8
Assumptions
Butler Operated Area:
Marcellus
Butler Operated Area:
Upper Devonian
Warrior Prospects:
Liquids-rich Utica
Unproved Prospective Acreage3
~39,700
~45,900
~17,800
Well Spacing4
83 Acres
98 Acres
146 Acres
N/A
Gross Potential Well Locations4
480
467
121
N/A
Current EUR5
5.3 Bcfe
4.3 Bcfe
1.4 MMBOE
N/A
EUR w/ Ethane5
7.0 Bcfe
5.7 Bcfe
1.4 MMBOE
N/A
Royalty Burdens
16%
16%
20%
N/A
Resource Potential1
1,503.1 Bcfe
1,190.3 Bcfe
133.6 MMBOE
31,500 MBbls
Resource Potential w/ Ethane1
2,007.6 Bcfe
1,589.8 Bcfe
133.6 MMBOE
31,500 MBbls
6
Illinois Basin: ASP
N/A
Total Liquids-rich Resource Potential ~3.7 Tcfe / ~614 MMBOE (~4.6 Tcfe / ~765 MMBOE with full ethane recoveries2)
1. See notes on “Forward Looking Statements” and “Hydrocarbon Volumes” on pages 2&3
2. Represents potential ethane recoveries assuming a full ethane recovery scenario; see page 7 for
estimated yield for ethane recovery
3. Based on gross acreage position excluding acreage from proved developed and undeveloped reserves
4. See note on “Potential Drilling Locations” on page 3
5. EURs based on internal estimates, see notes on “Forward Looking Statements” and “Hydrocarbon
Volumes” on pages 2&3
6. Subject to terms and conditions of farm-in agreement
36
Rex Energy Ethane Resource Potential
Region
Net Unproved Resource
Potential (Bcfe)
Additional Ethane Recoveries
(Mcfe)
Net Unproved Resource Potential
w/ Ethane (Bcfe)
Upper Devonian:
Liquids Rich
1,190.3
399.5
1,589.8
Butler Marcellus:
Liquids Rich
1,503.1
504.5
2,007.6
Warrior
Prospect:
Liquids Rich
801.51
ASP: Oil
189.0
--
189.0
3,683.9
904.0
4,587.9
40%
10%
50%
TOTAL
% Liquids
--
801.51
1. Assumes additional ethane recovery
37
Wet Gas Economic Yields
$3.75 NYMEX equates to $3.95 per Mcf of net revenue
• $3.75 NYMEX Henry Hub
• $100.00 NYMEX WTI
Wellhead Production – 1 mcf of Natural Gas
Production by Product
Gross Realized by Product
Natural Gas
NGLs
.900 mcf
1.64 gallons/ mcf(1)
$3.42 net(2)
$2.03(3)
Aggregate Realized Price per 1 mcf at wellhead
$5.45
Gathering, transportation and operating expenses
$1.50
Net Income Less Operating Expenses
1.
2.
3.
4.
$3.95(4)
.85 gallon/ mcf is excluded since it is used as fuel for compressors at the Sarsen cryogenic plant (does not include ethane recovery)
$0.05 added to NYMEX Henry Hub for premium
NGL Price assumption of 52% of $100.00 NYMEX WTI
Does not include Rex’s 28% interest in cash flow from the cryogenic plant partnership
38
Butler Marcellus Operated Wells In Inventory
Pad
Gross Well Count
Net Well Count
Status
Plesniak
2
1.4
Currently Undergoing Completion
Meyer
1
0.7
Drilled Awaiting Completion
Bricker
1
0.7
Drilled awaiting completion
Wack
1
0.7
Drilled Awaiting Completion
Grubbs #1 (Super-rich Marcellus Test)
1
0.7
Drilled Awaiting Completion
Lynn N&S
2
1.4
Drilled Awaiting Completion
JRGL #1
1
0.7
Drilled Awaiting Completion
Breakneck Beagle Club
4
2.8
Drilled Awaiting Completion
Hufnagel
1
0.7
Drilled Awaiting Completion
Total Wells in Inventory
14
9.8
39
Butler Operated Drilling Schedule
Pad
Gross Well Count
Net Well Count
Status
Burgh (Upper Devonian test well)
1
0.7
Currently Drilling
Rape
1
0.7
Awaiting Drilling Rig
Lamperski
1
0.7
Awaiting Drilling Rig
Stebbins
1
0.7
Awaiting Drilling Rig
Drushel
1
0.7
Awaiting Drilling Rig
Total 2012 Drilling Program
5
3.5
2012 Butler County Operated Area Drilling Program
Gross
Net
Wells Drilled
20
14.0
Wells Fracture Stimulated
19
12.9
Wells Placed in Service
19
13.0
Wells Drilled Awaiting Completion
18
12.6
40
Ohio Utica Shale Drilling & Completion Schedule
Area
Pad
Gross Well Count
Net Well Count
Status
Warrior South
Guernsey #1
1
0.8
Drilled Awaiting Completion
Warrior South
Noble #1
1
0.8
Currently Drilling
Warrior South
Guernsey #2
1
0.8
Awaiting Drilling Rig
Total 2012 Utica Drilling Program
3
2.4
2012 Ohio Utica Shale Drilling Program
Gross
Net
Wells Drilled
4
3.2
Wells Fracture Stimulated
2
1.6
Wells Placed in Service
1
0.8
Wells Drilled Awaiting Completion
2
1.6
41
Current Hedging Summary – Full Year 2012-2013
Crude Oil(1)
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
4Q14
Volume Hedged
150,000
150,000
135,000
135,000
135,000
135,000
Ceiling
$ 111.08
$ 111.08
$ 112.56
$ 112.56
$ 112.56
$ 112.56
Floor
$ 68.39
$ 68.39
$ 72.44
$ 72.44
$ 72.44
$ 72.44
Volume Hedged
--
--
--
--
--
--
48,000
48,000
48,000
48,000
Ceiling
--
--
--
--
--
--
$ 106.25
$ 106.25
$ 106.25
$ 106.25
Floor
--
--
--
--
--
--
$ 80.00
$ 80.00
$ 80.00
$ 80.00
Short Put
--
--
--
--
--
--
$ 65.00
$ 65.00
$ 65.00
$ 65.00
Collar Contracts
Three-Way
Collars
Natural Gas Liquids (Propane)(1)
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
Volume Hedged (Bbls)
27,000
27,000
27,000
27,000
27,000
27,000
Price per Barrel(2)
$ 43.26
$ 43.26
$ 43.26
$ 43.26
$ 43.26
$ 43.26
Price per Gallon(2)
$ 1.03
$ 1.03
$ 1.03
$ 1.03
$ 1.03
$ 1.03
Swap Contracts
1.
2.
Hedging position as of 8/31/2012
Hedges are indexed to Mt. Belvieu propane
42
Current Hedging Summary Cont’d
Natural Gas Hedges(1)
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
4Q14
Volume
1,590,000
1,590,000
1,560,000
1,470,000
1,470,000
1,470,000
300,000
300,000
300,000
300,000
Price
$ 4.17
$ 4.17
$ 3.79
$ 3.83
$ 3.83
$ 3.83
$ 3.42
$ 3.42
$ 3.42
$ 3.42
Volume
750,000
750,000
840,000
840,000
840,000
840,000
600,000
600,000
600,000
600,000
Ceiling
$ 5.89
$ 5.89
$ 5.68
$ 5.68
$ 5.68
$ 5.68
$ 4.45
$ 4.45
$ 4.45
$ 4.45
Floor
$ 4.70
$ 4.70
$ 4.77
$ 4.77
$ 4.77
$ 4.77
$ 3.52
$ 3.52
$ 3.52
$ 3.52
Volume
--
--
660,000
660,000
660,000
660,000
--
--
--
--
Floor
--
--
$ 5.00
$ 5.00
$ 5.00
$ 5.00
--
--
--
--
Volume
660,000
660,000
630,000
630,000
630,000
630,000
150,000
150,000
150,000
150,000
Ceiling
$ 5.13
$ 5.13
$ 4.88
$ 4.88
$ 4.88
$ 4.88
$ 4.25
$ 4.25
$ 4.25
$ 4.25
Floor
$ 4.48
$ 4.48
$ 4.17
$ 4.17
$ 4.17
$ 4.17
$ 3.50
$ 3.50
$ 3.50
$ 3.50
Short Put
$3.66
$3.66
$ 3.35
$ 3.35
$ 3.35
$ 3.35
$ 2.75
$ 2.75
$ 2.75
$ 2.75
Swap Contracts
Collar Contracts
Put Contracts
Collar Contracts
with Short Puts
1.
Hedging position as of 8/31/2012
43
Management Team
Management Team
Title
Thomas C. Stabley
Chief Executive Officer
Patrick M. McKinney
President & Chief Operating Officer
Michael L. Hodges
Chief Financial Officer
Curtis J. Walker
Chief Accounting Officer
David E. Pratt
Senior Vice President & Exploration Manager
Christina K. Marshall
Senior Vice President, Human Resources &
Administration
F. Scott Hodges
Senior Vice President, Land
Jennifer L. McDonough
Vice President, General Counsel & Secretary
44