Rex Energyrexenergycorp.com/3Q12ConferenceCallSlides.pdf.pdf · assurance they will prove to have been correct. ... and other descriptions of volumes of potentially ... • Entered

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

Responsible Development of America’s Energy Resources

Rex Energy

Third Quarter 2012 Conference Call

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.

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

Forward Looking Statements

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.

Estimates Used in This Presentation

3

Highlights and Recent Development

• Average daily production of 71.1 MMcfe/d

• 63% growth in production year-over-year

• 17% increase in liquids production year-over-year

• Entered into anchor/shipper ethane transportation agreement

with Enterprise Products Partners

• Pallack & Plesniak pads completion utilizing “Super Frac”

design; yields increased liquids profile

• Placed into sales first Ohio Utica well – Brace #1H

• 5-day sales rate of 1,008 boe/d1

• 30-day sales rate of 731 boe/d1

• Completed drilling last of three planned wells in Warrior South;

Expect to begin completing first well in November 2012

• Illinois Basin conventional drilling production expected to

exceed previous guidance of 400 gross BOPD

Financial Highlights

• Increased operating revenues 27% over 3Q11

• EBITDAX from continuing operations increased 19% over 3Q11

4

1 Assumes full ethane recovery

Selected Operational and Financial Highlights

5

4th Quarter

2011

1st Quarter

2012

2nd Quarter

2012

3rd Quarter

2012

Quarter to Quarter

Change % Change

Production – Average Per Day

Oil (Bbls) 1,919 1,892 1,859 1,987 ↑128 ↑7%

Gas (Mcf) 34,175 45,156 46,332 52,891 ↑6,559 ↑14%

Natural Gas Liquids (Bbls) 579 698 840 1,050 ↑210 ↑25%

Mcfe 49,162 60,696 62,529 71,111 ↑8,582 ↑14%

Production Mix By Type

Oil 23% 19% 18% 17% ↓1% ↓6%

Gas 70% 74% 74% 74% - -

Natural Gas Liquids 7% 7% 8% 9% ↑1% ↑13%

Lease Operating Expense $9.1 $9.51 $11.0 $11.2 ↑$0.2 ↑2%

Lease Operating Expenses per Mcfe $2.00 $1.72 $1.93 $1.72 ↓$0.21 ↓11%

Net Income, Adjusted2 $9.0 $5.3 $0.6 $4.0 ↑$3.4 ↑567%

Net Income Per Share, Adjusted $0.21 $0.11 $0.01 $0.08 ↑$0.07 ↑700%

EBITDAX from continuing ops $19,837 $21,218 $17,959 $22,815 ↑$4,856 ↑27%

1 Does not include $2.8 million of expense related to retroactive portion of new Pennsylvania impact fee. Actual expense was $12.3 million. 2 Refer to adjusted earnings slide in appendix for reconciliation

Price Realizations

4th Quarter

2011

1st Quarter

2012

2nd Quarter

2012

3rd Quarter

2012

Average Price Per Unit:

Realized crude oil price per Bbl – as reported $90.45 $99.31 $89.97 $89.00

Realized impact from cash settled derivative per Bbl ($0.13) ($1.23) ($0.44) --

Net realized price per Bbl $90.32 $98.08 $89.53 $89.00

Realized natural gas price per Mcf – as reported $3.80 $2.74 $2.41 $2.98

Realized impact from cash settled derivatives per Mcf $0.77 $0.97 $1.25 $0.85

Net realized price per Mcf $4.57 $3.71 $3.66 $3.83

Realized natural gas liquids price per Bbl – as reported $54.10 $48.98 $30.39 $40.95

Realized impact from cash settled derivatives per Bbl -- -- $1.22 $1.60

Net realized price per Bbl $54.10 $48.98 $31.61 $42.55

6

Current Hedging Summary

7

73% 67% 25% 62% 69% 30% 54% 57% 0%

10%

20%

30%

40%

50%

60%

70%

80%

2012 2013 2014

Co

mm

od

ity

% H

edg

ed

Commodity

Oil

Natural Gas

Propane

Current Production Hedged(1)

1. Percentage hedged based on mid-point of 4Q guidance with standard decline for 2014

2. Portions of production hedged with collars with short puts. See Appendix for more information

3. Excludes 2014 Natural Gas Call Contracts, see hedging information in Appendix for more information

4. Assumes that propane comprises ~50% of NGL volumes

(2) (2) (2)(3)

(4)

$68.39

$4.37

$1.03

$72.44 $4.32

$1.03

$80.00

$3.54

Fourth Quarter and Full Year 2012 Guidance

Fourth Quarter

2012

Full Year

2012

Average Daily Production 70.0 – 74.0 MMcfe/d 66.0 – 69.0 MMcfe/d

Lease Operating Expense $11.5 - $13.0 million $46.0 – $50.0 million

Cash G&A $5.3 - $6.3 million $20.0 - $24.0 million

Capital Expenditures N/A $180.0 million

8

• Initial gas analysis indicates over 56% higher C3+ liquids concentration in

Pallack pad and Plesniak 3H compared to average Butler Operated Marcellus

wells

• C3+ liquids yield increases from 37 Bbls/mm to 58 Bbls/mm of inlet

• Currently drilling third Upper Devonian test well; further testing for increased

liquids content

• Two Super Rich Marcellus test wells drilled; planned completion in 2013;

further testing for increased liquids content

• Upper Devonian Rhinestreet test well drilled; currently flowing back; further

testing for increased liquids content

Butler Operated Area Highlights

9

1. Assumes full ethane recovery unless otherwise noted

2. Includes 1 Utica Shale well in Butler County

2012 Butler County Drilling Program Well Counts2

Wells Drilled Fracture Stimulated Placed in Service Awaiting

Completion

20 20 21 18

Completed Pads

Pads Awaiting Completion

Butler Operated Area Plesniak #3H1

Natural

Gas

(mcf/d)

Condensate

(bbls/d)

NGLs

(bbls/d)

Total

(mcfe/d)

%

Liquids

Total

(Ethane

Rejection)

5-day rate 2,048 6 406 4,521 55% 3,171

25-day

rate

1,931 6 383 4,263 55% 2,991

Pallack Wells (Average)1

Natural

Gas

(mcf/d)

Condensate

(bbls/d)

NGLs

(bbls/d)

Total

(mcfe/d)

%

Liquids

Total

(Ethane

Rejection)

5-day rate 2,016 4 391 4,385 54% 3,070

30-day

rate

1,740 3 337 3,782 54% 2,648

10

Marcellus “Super Frac” Type-Curve Results

Drushel 3H (150 ft design) “Super Frac”:

• Job Performed: April; 2011; On Prod: +1 Year

• Lateral Length: 3,000’; 21 Stages

Behm 1H (150 ft design) “Super Frac”:

• Job Performed: June 2011; On Prod: +1 Year


Carson 3H (150 ft design) “Super Frac”:

• Job Performed: March 2012; On Prod: ~150 days


Carson 1H (225 ft design) “Super Frac”:

• Job Performed: March 2012; On Prod: ~150 days


Pallack (2) (150 ft design) “Super Frac”:

• Job Performed: Aug. 2012; On Prod: ~60 days


Plesniak (2) (150 ft design) “Super Frac”:

• Job Performed: Sept. 2012; On Prod: ~30 days


“Super Frac”: Type-Curve Considerations as

compared to YE 2011- 5.3 BCFE Type Curve

Lateral Spacing: 450 - 600 feet apart

Type curve validates lower initial first year decline

rate

Lateral Spacing: 950 feet apart

225’ stage spacing versus 150’ stage spacing

Lateral Spacing: 900 feet apart

150’ stage spacing

Restricted choke production test flowback

Lateral Spacing: No interference (North/South)

150’ stage spacing

Plesniak #3H: Restricted choke production test

flowback

Plesniak #9H: Extended Shut-in period

Ohio Utica – Warrior North Prospect

11 1. Assumes full ethane recovery

• 15,800 gross / 15,500 net acres in Carroll County, OH

• First well, Brace #1H, into sales in 3Q12

• Encountered over 135’ of Point Pleasant and 143’ of Utica pay

zone

• Oil / condensate / liquids rich gas zone

• 1,094 boe/d 24-hour sales rate; 1,008 boe/d 5-day sales rate;

30-day sales rate 731 boe/d

• Micro-seismic confirms “Super Frac” completion going forward

• ~ 70 net drilling locations in Warrior North Prospect

Warrior North Drilling Program

Year Wells Drilled Fracture

Stimulated

Placed in

Service

Awaiting

Completion

2012E 1 1 1 0

CHK Mangun 22-15-5 8H:

1.5 Mboe/d

CHK Neider 10-14-5 3H:

1.6 Mboe/d – Peak Rate

CHK Shaw 20-14-5H:

1.4 Mboe/d

CHK Burgett #7-15-6-8H:

1.2 Mboe/d

CHK Buell 10-11-5 8H:

3.0 Mboe/d – Located 10

miles south in Harrison

County

REXX Brace 1H: 30-day

sales rate: 731 boe/d

CHK White 17-13-5 8H:

1.4 Mboe/d

CHK Houyouse 15-13-5

#8H: 1.7 Mboe/d

EVEP Cairns 5H: 1.7

Mboe/d

CHK Coniglio 6H:

1.1 Mboe/d

Warrior North Prospect

Completed Wells

Potential Pad Location

Brace #1H Results1 (Boe/d)

Natural

Gas

Condensate NGLs Total %

Liquids

Total

(Ethane

Rejection)

24-hour sales

rate

336 291 467 1,094 69% 911

5-day sales

rate

306 273 429 1,008 70% 839

30-day sales

rate

221 202 308 731 70% 610

Ohio Utica – Warrior South Prospect

12

• 6,200 gross / 4,000 net acres1 in Guernsey, Noble and

Belmont Counties, OH

• Joint Development Agreement with MFC Drilling and

ABARTA Oil & Gas Co.

• Acreage within liquids rich window of the Utica Shale

• Drilling third of three planned wells

• Currently planning to frac three wells by end of 2012

• ~20 potential net drilling locations

• Actively leasing in the area

1. Subject to terms and conditions of farm-in agreement

2. At year end 2012 wells will still be on 60-day shut-in

Warrior South Drilling Program


Stimulated2

Placed in

Service

Awaiting

Completion

2012E 3 1 0 2

REXX –Three

Well Pad

Guernsey#1H

Noble#1H

Guernsey #2H

Antero Miley 5-H

Proposed MWE

Liquids Line

GPOR – Groh 1-12H:

Rate of 1.9 Mboe/d;

74% Liquids GPOR – Wagner 1-

28H: Test Rate of 5.2

Mboe/d; 16% Liquids

GPOR – Shugert 1-1H:

Test Rate of 5.5 Mboe/d;

39% Liquids

Warrior South Prospect

Appalachian Basin Processing Capacity

13 • Over 1 Bcf/d of planned processing capacity currently under construction

MWE – Harrison I

Processing &

Fractionation Complex:

125 MMcf/d

MWE – Noble 1

Processing Complex:

200 MMcf/d

REXX Warrior

South Acreage

Dominion –

Hastings Plant: 180

MMcf/d

Dominion –

Natrium Plant:

200 MMcf/d;

36,000 b/d

fraction capacity

REXX Butler

Operated Acreage

MWE – Sarsen &

Bluestone Processing

Complex: 90-190 MMcf/d

MWE – Houston

Processing &

Fractionation Complex

EPD ATEX Express

Pipeline

REXX Carroll

County Acreage

Mariner East

Pipeline

Mariner West

Pipeline

Dominion East

Ohio Pipeline

Currently in Service

Under Construction

Illinois Basin – Conventional Drilling

14

Gibson and Posey Counties Conventional Drilling Program


Stimulated

Placed in

Service

Awaiting

Completion

2012E 7 21 21 0

Illinois Basin Conventional • Rex Energy has identified multiple conventional infill and

recompletion opportunities in our Gibson and Posey

County, IN acreage

• 6,500 gross / 6,300 net acres

• Provide attractive rates of return in current price

environment

• Low risk and modest capital commitment with a

meaningful impact on near-term production

• 2012 expected activity of:

• 14 vertical recompletions

• 7 infill drilling opportunities

• 2012 investments expected to increase production

~400 gross BOPD by year end

15

Lawrence Field

Lawrence Field ASP • 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

• Current proved reserves booking of 13% of pore volume continues to be

confirmed

• Perkins-Smith Unit Pilot Expansion

• ASP injection commenced in June 2012

• Initial project response expected by second quarter of 2013

• Delta Unit Full Scale Commercial Expansion

• Core studies and geologic mapping complete

• Drilling of additional pattern wells complete

• Injection line tie-in complete

• Commenced 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

Middagh Pilot

15 Acres

Perkins-Smith

58 Acres

Delta Unit

Marcellus Non-Operated Overview

• Seven wells in Westmoreland County on the Marco #1

and National Metals #1 pads are producing above the

current type curve

• 200-day rates are still 50% above type curve

• Reduced Cluster Spacing (RCS) test performed

on National Metals wells

• EUR on last 12 wells completed are all exceeding a 6.0

BCF type curve

• No further wells planned to be drilled in 2012

16

Marcellus Non-Operated Drilling Program


Stimulated

Placed in

Service

Awaiting

Completion

2012E 5 2 2 7

Marcellus Non-Operated

Westmoreland

County Non-

Operated Area

Clearfield-Centre

County Non-

Operated Area


Rex Energy

Question and Answer Session


Rex Energy

Appendix

EBITDAX

($ in thousands) 2nd Quarter 2012 3rd Quarter 2012

9 Months Ending

9/30/12

Net Income From Continuing Operations 56,193 (1,742) 58,281

Net (Income) Loss Attributable to Non-Controlling Interests (222) (193) (516)

Income From Continuing Operations Attributable to Rex Energy 55,971 (1,935) 57,765

Add Back (Less)

Retroactive Portion of PA Impact Fee -- -- 2,809

DD&A & Accretion 10,884 12,396 33,082

Non-Cash Compensation 362 1,305 2,147

Interest Expense 1,322 852 3,655

Impairment Expense 273 292 3,357

Exploration Expense 1,213 1,206 3,511

(Gain) Loss on Disposal of Assets (92,679)1 526 (92,128)1

Unrealized (Gain) Loss on Financial Derivatives 1,654 10,166 8,167

Less Non-Cash Portion of Non-Controlling Interests (18) (36) (64)

Income Tax Expense (Benefit) 35,268 (2,131) 35,768

Equity Method EBITDAX 3,709 174 4,294

EBITDAX From Continuing Operations 17,959 22,815 62,363

EBITDAX From Discontinued Operations (341) (171) (848)

EBITDAX (Non-GAAP) 17,618 22,644 61,515

19 1. Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million

Adjusted Net Income

(in thousands) 2nd Quarter 2012 3rd Quarter 2012

9 Months Ending

9/30/12

Income From Continuing Operations Before Income Taxes, as reported 91,461 (3,873) 94,049

Add Back (Less):

Retroactive Portion of PA Impact Fee - - 2,809

Unrealized Gain on Derivatives 1,654 10,166 8,167

Non-Cash Compensation 362 1,305 2,147

Loss on Disposal of Assets (92,679)1 526 (92,128)

Impairment of Unproved Properties 273 292 3,357

Dry hole expense 52 - 306

Non-Controlling Interest Share of Net Income (222) (193) (516)

Income Before Income Taxes, adjusted 901 8,223 18,191

Less Income Tax Expense, adjusted (2) 349 4,243 6,949

Adjusted Net Income (Non-GAAP) 552 3,980 11,242

1. Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million

2. Income tax adjustment represents the effect of our effective tax rate on Income (Loss) From Continuing Operations Before Income Taxes, adjusted

20

Current Hedging Summary

21

Crude Oil(1)

4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14

Collar Contracts

Volume Hedged 150,000 135,000 135,000 135,000 135,000 -- -- -- --

Ceiling $ 111.08 $ 112.56 $ 112.56 $ 112.56 $ 112.56 -- -- -- --

Floor $ 68.39 $ 72.44 $ 72.44 $ 72.44 $ 72.44 -- -- -- --

Three-Way

Collars

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

Natural Gas Liquids (Propane)(1)(2)

4Q12 1Q13 2Q13 3Q13 4Q13

Swap Contracts

Volume Hedged (Bbls) 27,000 27,000 27,000 27,000 27,000

Price per Barrel $ 43.26 $ 43.26 $ 43.26 $ 43.26 $ 43.26

Price per Gallon $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03

1. Hedging position as of 10/31/2012

2. NGL hedges are indexed to Mt. Belvieu propane

Current Hedging Summary (Cont’d)

22


2. Swap contract volumes and average prices includes swaption hedges

Natural Gas Hedges(1)

4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14

Swap Contracts(2)

Volume 1,590,000 1,710,000 1,620,000 1,620,000 1,620,000 300,000 300,000 300,000 300,000

Price $ 4.17 $ 3.85 $ 3.89 $ 3.89 $ 3.89 $ 3.42 $ 3.42 $ 3.42 $ 3.42

Collar Contracts

Volume 750,000 840,000 840,000 840,000 840,000 450,000 450,000 450,000 450,000

Ceiling $ 5.89 $ 5.68 $ 5.68 $ 5.68 $ 5.68 $ 4.43 $ 4.43 $ 4.43 $ 4.43

Floor $ 4.70 $ 4.77 $ 4.77 $ 4.77 $ 4.77 $ 3.51 $ 3.51 $ 3.51 $ 3.51

Put Contracts

Volume -- 660,000 660,000 660,000 660,000 -- -- -- --

Floor -- $ 5.00 $ 5.00 $ 5.00 $ 5.00 -- -- -- --

Current Hedging Summary (Cont’d)

23


Natural Gas Hedges(1)

4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14

Call Contracts

Volume -- -- -- -- -- 450,000 450,000 450,000 450,000

Ceiling -- -- -- -- -- $ 5.00 $ 5.00 $ 5.00 $ 5.00

Collar Contracts

with Short Puts

Volume 660,000 630,000 630,000 630,000 630,000 450,000 450,000 450,000 450,000

Ceiling $ 5.13 $ 4.88 $ 4.88 $ 4.88 $ 4.88 $ 4.75 $ 4.75 $ 4.75 $ 4.75

Floor $ 4.48 $ 4.17 $ 4.17 $ 4.17 $ 4.17 $ 3.63 $ 3.63 $ 3.63 $ 3.63

Short Put $ 3.66 $ 3.35 $ 3.35 $ 3.35 $ 3.35 $ 2.75 $ 2.75 $ 2.75 $ 2.75

Documents

Rex Energyrexenergycorp.com/3Q12ConferenceCallSlides.pdf.pdf · assurance they will prove to have been correct. ... and other descriptions of volumes of potentially ... • Entered