2. Forward‐Looking Statements, Oil and Gas Reserves and Definitions
Forward‐Looking Statements
Certain statements contained herein that are not descriptions of 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. Because such statements include risks, uncertainties and contingencies,
actual results may differ materially from those expressed or implied by such forward‐looking statements. These risks, uncertainties and contingencies include, but are
not limited to, the following: our ability to successfully complete the acquisition of Eagle Ford Hunter, Inc. (“MHR”), as described herein, integrate the business of MHR
with ours and realize the anticipated benefits from the acquisition; any unexpected costs or delays in connection with the acquisition of MHR; the volatility of
commodity prices for oil, natural gas liquids and natural gas; our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; our
ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write‐downs or write‐offs of
our reserves or assets; the projected demand for and supply of oil, natural gas liquids and natural gas; reductions in the borrowing base under our revolving credit
facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and
gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of
production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability to
compete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets and repay our debt; leasehold
terms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of
necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access
adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or
attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental
regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international
economic and political conditions; and other risks set forth in our filings with the Securities and Exchange Commission (SEC).
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. Many of the factors that will
determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward‐looking statements,
which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward‐looking statements, or to make any other
forward‐looking statements, whether as a result of new information, future events or otherwise.
Oil and Gas Reserves
Effective January 1, 2010, the SEC permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves, but also “probable” reserves and
“possible” reserves. As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any
reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not
necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in
PVA’s Annual Report on Form 10‐K for the fiscal year ended December 31, 2012, which is available from PVA at Four Radnor Corporate Center, Suite 200, Radnor, PA
19087 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC’s website at www.sec.gov.
Definitions
Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be
economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulation
before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the
estimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves, but which are as likely than not to be recoverable (there should be at least a 50% probability that the quantities actually recovered will equal or exceed the
proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should be
at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). “3P” reserves refer
to the sum of proved, probable and possible reserves. Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date and cumulative production
as of that date. EUR is a measure that by its nature is more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and
accordingly is less certain. 1
3. Penn Virginia Corporation Overview
Company Overview Financial and Operational Summary
• Domestic onshore E&P company with Eagle Ford focus
Financial Summary
• The past two years have been transformational, with
portfolio transitioning to oil and liquids Common Equity Market Capitalization (4/2/2013)(3) $263MM
• Discontinued any material gas drilling
Convertible Preferred(4) $115MM
• HBP natural gas reserves in East Texas, the Mid‐Continent
and Mississippi Equity Market Capitalization $378MM
• Executing a strategy of growth in oil and NGL rich plays
• Successful drilling results in the Eagle Ford Shale – 117 wells
on‐line (71 legacy PVA and 46 legacy MHR)(1) Operational Summary
• Adding to Eagle Ford drilling inventory
Pro Forma Production(5)
– Successful exploratory results in Lavaca County
– Approximately 640 (420 net) drilling locations remaining 2012 Q4 Average Daily Prod. (MBOEPD) 18.2
currently(1)
• Strategy has resulted in significant growth in EBITDAX and February 2013 Production (MBOEPD) 19.5
cash operating margins
• Focused on improving liquidity Pro Forma Proved Reserves (MMBOE) 125.5
• Cash plus revolver availability of $316MM at YE12 ($321MM
pro forma(2)) % Liquids 46%
• Leverage ratio (net) of 2.3x at YE12 (3.3x pro forma)
% Proved Developed 41%
• Over 69% of 2013 oil production (PVA stand‐alone) hedged
at weighted average price of $96.67 per barrel (WTI)
• Over 68% of 2013 gas production (PVA stand‐alone) hedged
at weighted average price of $3.77 per MMBtu (HH)
(1) Pro forma for the MHR acquisition as of April 3, 2013 (the “Acquisition”).
(2) Current borrowing base of $300MM will be adjusted to $276.3MM at closing of the Acquisition, pending borrowing base redetermination. Pro forma availability assumes no borrowings under the
revolver and $2.1MM in letters of credit outstanding as of December 31, 2012. Liquidity assumes $46.8MM of pro forma cash and cash equivalents as of December 31, 2012.
(3) Reflects share price of $4.41 as of April 11, 2013; includes new common equity issuance in the amount of $40MM.
(4) Net issue proceeds of convertible preferred at 6%.
2
(5) Figure is pro forma for asset sales and acquisitions.
4. Transformational Acquisition
Greater scale: ~83,000 (54,000 net) Eagle Ford acres and substantial growth in oil production/revenue
• Purchase price of approximately $400MM for ACREAGE
MHR LEGACY
40,565 (19,037 net) highly contiguous net acres PVA LEGACY
OPERATOR
in Gonzales and Lavaca Counties EOG
MAGNUM HUNTER
PVA
• Year‐end 2012 SEC proved reserves of 12.0 HUNT MHR
MARATHON
MMBOE(1)
– Oil = 90% of proved reserves
– 37% proved developed Gonzales
PVA
• Year‐end 2012 SEC PV‐10 of $241MM(1)
HUNT
– PD PV‐10 of $156MM
• Year‐end reserves include 44 proved
developed locations and 51 locations booked PVA
EOG
as PUDs(1)
• Expands existing footprint and acreage is largely
MRO
adjacent to existing position
Lavaca
• Acquired assets add up to 345 gross (169
net) locations(2)
EOG
DeWitt
3
(1) As of December 31, 2012 per March 28, 2013 reserve report prepared by Cawley, Gillespie & Associates.
(2) As of April 3, 2013.
5. Transformational Acquisition (cont.)
Acquisition Impacts to PVA’s Asset Profile
Growth in Key Corporate Metrics as a Result of Acquisition Growth in Key Eagle Ford Metrics as a Result of Acquisition
Proved Proved
Devel oped 9% Devel oped 45%
Res erves Res erves
Tota l Proved Tota l Proved
11% 46%
Res erves Res erves
Tota l Proved Oi l Tota l Proved Oil
Res erves 44% 53%
Res erves
Februa ry 2013 Februa ry 2013
Da i l y Producti on
20% 42%
Da il y Producti on
Net Inventory 28% Net Inventory 68%
Net Acres 10% Net Acres 54%
Acquisition Significantly Increases PVA’s Eagle Ford Position and Overall Scale in the Eagle Ford
4
Note: Reserves as of 12/31/2012 . All other figures as of April 3, 2013 unless otherwise stated.
6. Sources & Uses / Pro Forma Capitalization
Sources ($ in millions) Pro Forma Capitalization
New Seni or Notes $775 Eagle Ford Acq. PVA Pro Forma
Equi ty Is s ua nce (1) 40 ($ in millions) 12/31/2012 Adjustments 12/31/2012
(5)
Total Sources $815 Ca s h a nd Ca s h Equi va l ents $18 $29 $47
(6)
Uses ($ in millions) Revol vi ng Credi t Fa ci l i ty ‐ ‐ ‐
Acqui s i ti on Cons i dera ti on $400 10.375% Seni or Notes due 2016 300 (300) ‐
Refina nce 2016 Seni or Notes 300 7.250% Seni or Notes due 2019 300 ‐‐ 300
Pos t Cl os i ng Adjus tments (2) 43 New Seni or Notes ‐ 775 775
Premi um on Tender(3) 18 Tota l Debt $600 $475 $1,075
Es ti ma ted Fees a nd Expens es (4) 25
Ca s h to Ba l a nce Sheet 29 6% Converti bl e Preferred $115 ‐‐ $115
Total Uses $815
Proved Res erves (MMBoe) 113.5 12.0 125.5
% Oi l 22% 90% 28%
% Li qui ds 40% 96% 45%
% Devel oped 41% 37% 41%
Q4 2012 Producti on (MBoe/d) 15.4 2.7 18.2
Proved R/P (Yea rs ) 20.1x 12.2x 18.9x
PD R/P (Yea rs ) 8.3x 4.4x 7.8x
PT Proved PV‐10% $692 $241 $933
(1) MHR has agreed to backstop the equity portion of the Acquisition and we have assumed we issue 10MM shares at $4.00 per share ($40MM) as equity consideration.
(2) PVA estimate based on closing date of May 15, 2013.
(3) Existing 10.375% senior notes due 2016 are assumed to be repurchased at the tender price of 106.00%; assumes settlement date of May 2, 2013.
(4) Fees and expenses include 2.5% underwriting fee for High Yield issuance, 1.50% bridge commitment fee, $1.0MM in legal and other fees, and a $1.0MM advisory fee. Assumes no equity
issuance fee due to backstop.
(5) As of March 31, 2013, PVA had cash and cash equivalents of $10.7MM. Subsequently, in connection with entering into the stock purchase agreement relating to the acquisition, PVA
borrowed $5MM under its revolving credit facility and paid a $10MM deposit to MHR, which will be applied towards the purchase price at the close of the acquisition. 5
(6) As of March 31, 2013, PVA had $38MM outstanding under its revolving credit facility.
7. Eagle Ford Shale Operators
Eastern Volatile Oil Windows(1)
Volatile Oil
Condensate
Rich Gas
EFS Operators Gonzales
PVA
MHR
San Antonio
Hunt
Wilson
BHP Bexar
CHK Lavaca
COG
COP
Atascosa
CRK DeWitt
CRZO
EOG
FST
MRO Victoria
MUR
NFX
PXD
PXP
SFY Goliad Texas
STO
TLM
Bee
McMullen Live Oak
Note: Some EFS operators off map.
6
(1) Based on latest company presentations, as well as industry publications. Some industry publication information may be out of date.
8. Expanded Eagle Ford Acreage Position
(Net acreage in thousands)
• Net acreage by operator across entire Eagle Ford play
• Operators’ disclosed acreage includes leaseholds outside volatile oil window
• Approximately all of PVA’s leasehold is in the volatile oil window
341
90
138
118
80
72
70 67
62
60
60
54 54 53
50
40 39
40
35
30 28 28
24
22
20
10 9 7
0
BHP SN PXD ZAZA ROSE COG PXP PVA PF SFY CRZO FST GDP PVA CRK MTDR HK Aurora CXPO AXAS
Source: Company investor presentations and SEC filings through April 3, 2013. 7
9. PVA’s Pro Forma Eagle Ford Shale Position
Sizeable Position in a Successful Portion of the Eastern Oil Window of the Eagle Ford Shale
Premier Shale Oil & Liquids Play • 82,995 gross (≥54,057 net) acres in Gonzales and Lavaca
Counties, TX(1)
• Operator of 46,452 (32,410 net) acres in Gonzales ‐ 70% WI
Gonzales • Operator of 23,203 (15,148 net) acres in Lavaca ‐ 65% WI(1)
• Non‐operator of 13,340 (6,499 net) acres in Gonzales ‐ 49% WI
• Avg. IP/30‐day rates of 1,066/676 BOEPD
• Gonzales type curve EUR of ≥400 MBOE(2)
Lavaca • Lavaca type curve EUR of ≥500 MBOE(2)
• Proved reserves of 38.2 MMBOE at year‐end 2012, consisting
of 82% oil, 10% NGLs and 8% gas
• Proved PV‐10 at YE12 of $933MM ($784MM of PD value)
• 117 (82.0 net) wells producing
• Objective is to lower PVA well costs by at least 10‐15% in 2013
DeWitt • Up to 640 (420 net) remaining drilling locations
• Initial positive down‐spacing tests of 3‐well pad in Gonzales
County and 2 closely spaced MHR wells in Lavaca County
Nearby Operators
• Includes over 300 infill locations
PVA Pro Forma Marathon
BHP Billiton Pioneer • Rigs, infrastructure in place
ConocoPhillips Plains • Dedicated rigs and frac crew
EOG Statoil
Forest
• Gas gathering and processing in place
• Receiving premium LLS base pricing
8
(1) Net acreage in Lavaca County is expected to increase due to non‐consents by our partner on initial wells in 17 drilling units.
(2) Based on 1/29/13 operational release, YE12 SEC reserve report prepared by Wright & Co. and YE12 SEC reserve report prepared by Cawley, Gillespie & Associates.
10. Acquired Asset in Detail
Total of 345 (169 net) locations across 40,565 (19,037 net) acres in Gonzales and Lavaca Counties
Gross Average
Prospect Area Acres Net Acres Royalty
Peach Creek (MHR) 19,722 9,166 20%
Peach Creek (Hunt JV) 13,340 6,499 20%
Shiner (GeoSouthern JV) 4,674 2,119 20%
Shiner 2,829 1,253 20%
Total / Average 40,565 19,037 20%
Gross Non‐ Net Non‐
Producing Producing Producing
Prospect Area Wells Locations Locations
Peach Creek (MHR) 27 149 73.1
Peach Creek (Hunt JV) 15 121 60.5
Shiner (GeoSouthern JV) 3 72 32.6
Shiner 1 3 3.0
Total 46 345 169.3
9
11. Combined Position Post Acquisition
Significant Eagle Ford Shale Acreage and Drilling Inventory
• Due to both acquisitions and leasing efforts over the past two years, our acreage position is
now 83,000 gross (~54,000 net) acres primarily in the volatile oil window(1)
• We also have a multi‐year inventory of up to 640 (420 net) additional drilling locations
• Successful down‐spacing testing has added over 300 potential infill locations to our inventory
• Locations will vary over time in terms of lateral length, frac stages, spacing and geology
• Recent successful wells in the southern and eastern portions of our Lavaca acreage have further “de‐
risked” our inventory
• Unitizations with other industry participants and continued leasing are expected to yield additional
locations
Producing Remaining Total Well Gross Net Acres /
Area
Wells Locations Locations Acreage Acreage(1) Location(2)
PVA Gonzales 54 190 244 26,239 21,261 108
PVA Lavaca 17 105 122 16,191 13,759 133
MHR Acquired 46 345 391 40,565 19,037 104
Pro Forma Total 117 640 757 82,995 54,057 110
(% Change) 65% 117% 107% 96% 54%
(1) Net acreage in Lavaca County is expected to increase due to non‐consents by our partner on initial wells in 17 drilling units. 10
(2) Represents gross acres per location.
12. Strong and Consistent Initial Production Rates
Both PVA’s legacy assets and the acquired position have strong and repeatable results
PVA Legacy Assets Acquired MHR Assets
Gonzales Lavaca Gonzales Lavaca
30‐Day Avg (BOEPD) IP (BOEPD) 30‐Day Avg (BOEPD) IP (BOEPD)
• Average Gonzales IP / 30‐Day Rate of 921 / 621 BOEPD • Average Gonzales IP / 30‐Day Rate of 1,065 / 678 BOEPD
• Average Lavaca IP / 30‐Day Rate of 939 / 644 BOEPD • Average Lavaca IP / 30‐Day Rate of 1,503 / 849 BOEPD
• Gonzales Averages of 15 Stages and 3,713’ Lateral Length (LL) • Gonzales Averages of 16 Stages and 4,605’ LL
• Lavaca Averages of 19 Stages and 4,583’ LL • Lavaca Averages of 22 Stages and 6,114’ LL
Note: The following PVA wells had operational difficulty or short laterals: Vana 1H, Pavlicek 1H, Rock Creek Ranch 7H and 8H, Cannonade Ranch 3H, Munson Ranch 9H, Rock Creek Ranch 3H and 4H. 11
13. Attractive Economics in Volatile Oil Window
Compelling Economics & Value at Varying Oil Prices
Gonzales County(1) Lavaca County(1)
• Assumptions • Assumptions
• Longer lateral lengths in 2013 vs. PUD assumption • Longer lateral lengths in 2013 vs. PUD assumption
• 460 MBOE EUR type curve • 590 MBOE EUR type curve
• Drilling and completion (D&C) costs per below • Drilling and completion (D&C) costs per below
D&C of D&C of D&C of D&C of
Key Takeaways Key Takeaways
$9.1MM $8.1MM $10.1MM $9.1MM
IRR 40 – 52% 52 – 76% IRR 37 – 52% 50 – 71%
BTAX PV‐10(2) ($MM) $5.6 – 7.4 $6.6 – 8.4 BTAX PV‐10(2) ($MM) $6.1 – 8.2 $7.1 – 9.2
Breakeven(3) ($/BOE) $47 – 57 $41 – 52 Breakeven(3) ($/BOE) $47 – 57 $42 – 52
GONZALES COUNTY LAVACA COUNTY
Pretax Rate of Return Sensitivities Pretax Rate of Return Sensitivities
100 100
90 $4.00/MMBtu Flat Gas Price 90 $4.00/MMBtu Flat Gas Price
Rate of Return BFIT - %
Rate of Return BFIT - %
80 80
70 70
60 60
50 50
40 40
30 30
20 20
10 10
0 0
40 50 60 70 80 90 100 110 120 40 50 60 70 80 90 100 110 120
Base Case EUR = 460MBOEWTI Oil Price
(8/8ths) Base Case EUR = 590MBOE (8/8ths) Base Case EUR = 590MBOE (8/8ths)
(Flat) - $/Bbl Case
Base EUR = 460MBOE (8/8ths)
WTI Oil Price
Capex = $10.1MM (8/8ths) LLS Pricing
(Flat) - $/Bbl = $10.1MM (8/8ths) WTI Pricing
Capex
Capex = $9.1MM (8/8ths) LLS Pricing Capex = $9.1MM (8/8ths) WTI Pricing
Sensitivity Case EUR = 460MBOE (8/8ths) Sensitivity Case EUR = 460MBOE (8/8ths) Sensitivity Case EUR = 590MBOE (8/8ths) Sensitivity Case EUR = 590MBOE (8/8ths)
Capex = $8.1MM (8/8ths) LLS Pricing Capex = $8.1MM (8/8ths) WTI Pricing Capex = $9.1MM (8/8ths) LLS Pricing Capex = $9.1MM (8/8ths) WTI Pricing
(1) Based on YE12 PUDs, excluding short‐length lateral wells, applied to longer length laterals in 2013 program.
(2) Assuming a flat $90 per barrel WTI oil price. 12
(3) Before tax PV‐10 breakeven WTI oil price.
14. Revised 2013 Capital Plan
2013 Capital Spending Focused on Eagle Ford Drilling
• Full‐year 2013 capital expenditures expected to be approximately $457MM(1)
• Four operated rigs with two on existing PVA acreage and two rigs on operated MHR acreage
• Two non‐operated rigs
• Incremental capital spending of approximately $77MM(1)
• Six‐rig drilling program (currently seven rigs running between PVA, MHR and Hunt)
• Adjusted EBITDAX expected to increase to between $295 and $350MM, or 25% over previous guidance
• 2013 capital spending is expected to be 92% Eagle Ford
• Maintenance and new ventures capital for other areas
Pro Forma Capital Expenditures by Area(1) Pro Forma Capital Expenditures by Type(1)
Other D&C
4%
Acquired Eagle
Ford Assets Land
28% 5%
Other
4%
Existing Eagle
Ford
64% Eagle Ford D&C
Mid‐Continent 87%
3%
Pearsall
2%
Other
3%
13
(1) Change in mid‐points of full‐year 2013 guidance, adjusted for acquired Eagle Ford assets.
15. Acquisition’s Effect on Production Volumes and Mix
Positive Production Trend
• During 2011 and into early 2012, we quickly ramped up Eagle Ford Shale production, and
expect to increase production once again during 2013
• Approximately 94% of sales volumes are liquids ‐ primarily crude oil
• Oil is sold into Gulf Coast LLS market through multiple purchasers at premium pricing to WTI
Pre Acquisition Eagle Ford Production (MBOEPD) Post Acquisition Eagle Ford Production (MBOEPD)
11.2
7%
$10 $10 7%
8.5
7.9 6%
8% 8%
6.4 8%
7%
9%
$5 $5 86%
86%
85%
2.3 84% 2.3
88% 88%
$0 $0
2011 2012 2013E 2011 2012 PF 2013E
Oil and Condensate NGLs Natural Gas
14
16. Current Geographic Footprint
Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays
Eagle Ford and Other Regions Appalachian Region
Mid‐Continent Cotton Valley Marcellus
Proved reserves: 12.5 MMBOE Proved reserves: 39.6 MMBOE Proved reserves: 0.5 MMBOE
% Oil/NGLs: 47% % Oil/NGLs: 34% % Gas: 100%
% PD: 79% % PD: 34% % PD: 23%
2012 Production: 1,211 MBOE 2012 Production: 882 MBOE 2012 Production: 43 MBOE
Haynesville
Proved reserves: 17.2 MMBOE
% Gas: 86%
% PD: 26%
2012 Production: 454 MBOE
Total Company
Pro Forma Eagle Ford Selma Chalk Pro Forma Penn Virginia
Proved reserves: 38.2 MMBOE Proved reserves: 17.6 MMBOE Proved reserves: 125.5 MMBOE
% Oil/NGLs: 92% % Gas: 99% % Oil/NGLs: 46%
% PD: 37% % PD: 54% % PD: 41%
2012 Production: 3,092 MBOE 2012 Production: 847 MBOE 2012 Production: 6,529 MBOE(1)
Note: Based on 1/29/13 operational release and year‐end 2012 SEC reserve report prepared by Wright & Company, Inc. SEC reserve report for acquired assets prepared by Cawley, Gillespie & Associates.
15
(1) Excludes divested production.
17. Pro Forma Total Company Drilling Inventory
Pro Forma PVA Has a Healthy Inventory of Drilling Locations
• Total inventory of up to 1,133 gross undrilled locations (952 horizontal locations)
• Up to 692 gross horizontal drilling locations in the Eagle Ford and Granite Wash
• Significant upside in inventory of “gassy” locations
Gross Undrilled Average Working Gross EUR
Play Locations Interest (MBOE/Well)(1)
Existing Eagle Ford (Gonzales) 190 83% 394
Existing Eagle Ford (Lavaca) 105 88% 513
Acquired MHR Assets 345 48% 385
Granite Wash 52 18% 809
Cotton Valley 78 71% 903
Haynesville 78 77% 869
Cotton Valley (vertical) 181 71% 172
Selma Chalk 104 96% 302
Totals 1,133
Note: Latest through April 3, 2013; excludes two Marcellus locations. 16
(1) Median gross EUR for all PUD locations.
18. Regional / Play Production Breakout
Expanding Production Volumes from Eagle Ford Assets
Production Volumes by Operating Region (MMBOE)
• Eagle Ford production
growth is PVA’s focus 6.8
going forward 6.2 (1)
(1)
5.8 18%
• Production volumes 14%
in the Eagle Ford are
12%
expanding from pro 40%
forma 40% in 2012 to 18% 42%
at least 60% in 2013
8%
15% 5%
35%
10%
21%
14%
21%
15% 11%
2011(1) 2012 (1) 2013E
Cotton Valley Mid‐Continent Selma Chalk
Marcellus Haynesville PVA Legacy Eagle Ford
Acquired MHR Eagle Ford
Note: 2013 annual production guidance of 6,518 MBOE – 7,175 MBOE, midpoint of 6,847 MBOE.
(1) Excludes divested production.
17
19. Increasing Liquids Production
Production Mix Over Time
• Since 2011, PVA has consistently grown its
annual liquids production
• The Acquisition will significantly increase
33%
liquids production and overall production
47%
growth 52%
• In 2013, 92% of PVA’s capex program will be 72%
12%
allocated to the Eagle Ford
• Expected to run six rigs in 2013, post 13%
acquisition 14%
• Shift in liquids focused production has resulted
in 2012 pro forma production being 53% 55%
liquids 12%
40%
35%
• 40% oil and 13% NGLs
17%
2011 2012 2012 PF 2013E
Oil & Condensate NGLs Natural Gas
Note: 2013 annual crude oil and NGLs production mix guidance of 64.5% ‐ 69.4%. 18
20. Oil Based Strategy Continues
• PVA has significantly increased its liquids percentage of revenue since the beginning of 2011
Annual Product Revenue by Commodity (Before Hedges) Annual EBITDAX
$322
$425
$300
$400
$248
$310
$300 $220
16% $200
10%
46%
$200 89%
Liquids
14% $100
74%
40%
$0 $0
2011 2012 2013E 2011 2012 2013E
Oil NGL Gas
19
Note: 2013E based on the mid‐point of updated guidance and price deck for 2013: ($90.96 / $3.51).
21. Operating Margins
Unhedged Cash Margin Over Time ($/BOE)
• PVA has consistently increased
$70
cash margin since 2011 through:
$62.02 Realized
• Investment in higher rate‐of‐ $60
$6.12
Price
return oil projects $52.62 $4.25
• Advantaged LLS pricing $50 $47.67 $4.58
$2.00
$1.55
$4.85
$5.11 $1.95
• Decreasing per unit operating $38.70
$1.63 $5.13
$40 $2.18
costs $5.28 $4.80
$1.74
• The Acquisition is expected to $30 $1.98
$4.74
further expand cash margins Cash
$45.25 Margin
$20 $38.96
$33.95
$24.96
$10
$0
2011 2012 2012 PF 2013E
Cash Margin LOE
G&P and transportation Production taxes
Cash G&A (excludes share‐based compensation)
Note: Cash margin ($ / BOE) is defined as total product revenues, excluding the impact of hedges, less direct operating expenses per unit of equivalent production. 20
Assumed price deck for 2013: ($90.96 / $3.51).
22. Strong Margins vs. Peers
• EBITDAX has increased significantly since mid‐2010 when we shifted our strategy to oil and NGLs
• Cash margin per BOE has also improved significantly due to the increase in oil prices and
declining operating costs per unit
• Eagle Ford cash margin was $79.00 / BOE in 4Q12(1)
Quarterly Adjusted EBITDAX and EBITDAX Margin ($ / BOE) Comparative Q4 2012 EBITDAX Margins ($ / BOE)(2)
$70
$66 $48.41
$64 $45.88
$62 $61 $62
$60 $43.72
$35.44
$40.61
$34.77
$34.51
$43.72
$39.10
$33.01
$49 $36.48
$39.73
$48
$46 $45 $44
$24.38
$21.72
$26.37
$20.73
$20.76
$33 $25.01 $24.54
$28.50
$22.95
$19.79
$18.91
$13.56
$0
(3)
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 PVA GDP PVA CWEI CRZO FST PDCE BBG CRK Antero XCO KWK
PF
Source: Company filings.
(1) Excludes regional and corporate G&A expenses.
(2) PVA 4Q2012 EBITDAX of $62.3MM per its earnings release. EBITDAX for peers calculated as total revenues less lease operating expenses, production taxes and cash G&A unless otherwise
disclosed. Inclusive of realized hedge gains or losses.
21
(3) Pro forma for the Acquisition.
23. Hedging Strategy
Protect Cash Flow
• Maintain an active hedging program to help support capital spending program and ensure strong
coverage metrics
• Hedges in place to protect cash flow
• Natural gas hedging is currently 68% of expected 2013 total volumes at an average floor price of $3.77 / Mcf
• Oil hedging is currently 69% of expected 2013 total volumes at an average floor price of $96.67 / barrel
– 35% hedged for 2014 (stand‐alone) of total volumes at $94.87 / barrel
• Upon closing the acquisition we will enter into additional hedges and expect the overall percent
of production hedged to closely resemble our current levels
Crude Oil Hedges (Swaps and Collars)(1) Natural Gas Hedges (Swaps and Collars)(1)
7,000 $110 30 $6
Weighted Avg. Floors and Swaps ($/MMBtu)
Weighted Average Ceiling /
Weighted Avg. Floors and Swaps ($/Bbl)
Weighted Average Ceiling /
Swap Price by Quarter Swap Price by Quarter
6,000 $105
$102 Weighted Average Floor /
25 $5
$101
Swap Price by Quarter $4.24 $4.27
5,000 $99 $99 $100 $4.16 $4.07 $4.07
MMBtu per Day (000s) $4.03 $4.03
20 $4
Barrels per Day
$98 $95 $4.02
$97 $94 $94 $3.82 Weighted Average Floor /
4,000 $96 $96
$95 $3.76 $3.75 $3.75
$95 Swap Price by Quarter
15 $3
3,000 $90
10 $2
2,000 $85
1,000 $80 5 $1
0 $75 0 $0
1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14
22
(1) As of 3/25/13.
24. Investment Highlights
• Transformational acquisition increases footprint ACREAGE
MHR LEGACY
in the volatile oil window core of the Eagle Ford PVA LEGACY
OPERATOR
• With 82,995 gross (54,057 net) of highly EOG
MAGNUM HUNTER
PVA
contiguous acres, our pro forma position will be HUNT MHR
MARATHON
significant with attractive leverage on a per share
basis
• MHR’s acreage is adjacent to our current position
Gonzales
with similar geologic and reserve characteristics
PVA
to our current Eagle Ford assets
HUNT
• Enhances production growth, with 2013E
production (7.5 months) of approximately 5,500
BOEPD, representing a 34% increase (23% PVA
EOG
increase in BOEPD on a full‐year basis)
• Increases drilling inventory in the Eagle Ford
Shale to 640 (420 net) locations MRO
• Attractive drilling economics with PV‐10 Lavaca
breakeven WTI prices of $47 ‐ $57 per barrel
• 11% increase in proved reserves by adding 12.0
MMBOE (96% liquids / 37% PD), increases Eagle EOG
Ford Shale proved reserve base by 46% DeWitt
23
26. Transaction Overview
• Penn Virginia is acquiring Eagle Ford Shale assets from Magnum Hunter for approximately $400MM
• Assets are adjacent to PVA’s current Eagle Ford position in Gonzales and Lavaca Counties
Transformational • 40,565 (19,037 net) acres in Gonzales and Lavaca counties
Acquisition in the • 46 (22.1 net) producing wells and drilling inventory of 345 (169 net) locations(1)
Eagle Ford Shale • Approximately 3,173 BOEPD – February 2013
• Approximately 5,500 BOEPD – 2013E (final eight months)
• 12.0 MMBOE of proved reserves (37% PD / 96% Liquids)(2)
• Transaction Value / Production ($ / BOEPD – February 2013) = ~$126,000
Attractive • Transaction Value / Production ($ / BOEPD – 2013E) = ~$73,000
Transaction
• Transaction Value / Proved Reserves ($ / BOE) = ~$33.00
Valuation
• Transaction Value / 2013E EBITDAX ($93MM over 7.5 months, annualized) = ~2.7x
• We have priced $775MM of 8.50% senior unsecured notes due 2020 in a private placement
Acquisition and • Up to $330MM for tender offer for $300MM of 10.375% senior notes due 2016 @ 106%
Tender Offer
• At least $400MM to fund the MHR acquisition
Financing
• Up to $40MM common equity option to issue up to 10MM shares to MHR @ $4/share
• April 2nd – PSA signed
• April 2nd – Acquisition announced
Closing Timeline • April 3rd – Commence private placement
• April 10th – Price upsized notes private placement
• By mid‐May 2013 – Close acquisition
25
(1) Inventory as of April 3, 2013 includes seven MHR/Hunt wells that are in the process of completion or waiting on completion.
(2) As of December 31, 2012 per March 28, 2013 reserve report prepared by Cawley, Gillespie & Associates.
27. Pro Forma Reserves, PV‐10 and Production by Region / Play
Proved Reserves (125.5 MMBOE) Proved Developed Reserves (51.4 MMBOE)
Marcellus Marcellus
Mid‐Continent
0% PVA Legacy 0% PVA Legacy
10%
Eagle Ford Mid‐Continent Eagle Ford
21% 19% 19%
Haynesville
14%
Acquired MHR
Haynesville Eagle Ford
Acquired MHR
9% 9%
Eagle Ford
10%
Selma Chalk
14%
Selma Chalk
Cotton Valley Cotton Valley
18%
32% 26%
Pre‐Tax PV‐10 ($933.2MM)(1) 2012 Production (17.8 MBOEPD)
Mid‐Continent Marcellus
11% 1%
Selma Chalk
2% Mid‐Continent
Cotton Valley PVA Legacy 18%
1% Eagle Ford PVA Legacy
65% Eagle Ford
36%
Haynesville
Acquired MHR 7%
Eagle Ford
26%
Selma Chalk
13%
Acquired MHR
Cotton Valley Eagle Ford
13% 12% 26
(1) Based on SEC pricing.
28. Full‐Year 2013 Guidance Table
Revised for Proposed MHR Acquisition Assuming 5/15/13 Closing Date
Current Full‐Year Adjustments for MHR Pro Forma
2013 Guidance Acquisition / One Less Rig 2013 Guidance
Production:
Crude oil (MBbls) 2,775 ‐ 3,075 760 ‐ 890 3,535 ‐ 3,965
NGLs (MBbls) 730 ‐ 820 55 ‐ 75 785 ‐ 895
Natural gas (MMcf) 13,000 ‐ 13,650 190 ‐ 240 13,190 ‐ 13,890
Equivalent production (MBOE) 5,672 ‐ 6,170 847 ‐ 1,005 6,518 ‐ 7,175
Equivalent daily production (BOEPD) 15,539 ‐ 16,904 3,681 ‐ 4,370 17,858 ‐ 19,658
Percent crude oil and NGLs 59.9% ‐ 64.9% 95.3% ‐ 96.8% 64.5% ‐ 69.4%
Production revenues (a):
Crude oil $265.0 ‐ $293.5 $70.0 ‐ $80.0 $335.0 ‐ $373.5
NGLs 21.5 ‐ 24.5 1.5 ‐ 2.0 23.0 ‐ 26.5
Natural gas 43.5 ‐ 45.5 1.0 ‐ 1.5 44.5 ‐ 47.0
Total product revenues $330.0 ‐ $363.5 $72.5 ‐ $83.5 $402.5 ‐ $447.0
Total product revenues ($ per BOE) $58.18 ‐ $58.91 $85.63 ‐ $83.08 $61.75 ‐ $62.30
Percent crude oil and NGLs 86.2% ‐ 88.0% 97.9% ‐ 98.8% 88.3% ‐ 90.0%
Operating expenses:
Lease operating ($ per BOE) $4.60 ‐ $5.00 $4.65 ‐ $5.05
Gathering, processing and trans. costs ($ per BOE) $1.70 ‐ $1.90 $1.45 ‐ $1.65
Production and ad valorem taxes (% of oil and gas revenues) 6.3% ‐ 6.9% 6.6% ‐ 7.1%
General and administrative:
Recurring general and administrative $39.5 ‐ $40.5 $1.8 ‐ $2.0 $41.3 ‐ $42.5
Share‐based compensation 3.0 ‐ 4.0 0.2 ‐ 0.3 3.2 ‐ 4.3
Restructuring 2.5 ‐ 2.7 2.5 ‐ 2.7
Total reported G&A $42.5 ‐ $44.5 $4.5 ‐ $5.0 $47.0 ‐ $49.5
Exploration:
Total reported exploration $28.0 ‐ $30.0 $18.0 ‐ $22.0 $46.0 ‐ $52.0
Unproved property amortization 21.0 ‐ 22.0 21.0 ‐ 24.0 42.0 ‐ 46.0
Depreciation, depletion and amortization ($ per BOE) $36.00 ‐ $39.00 $36.00 ‐ $39.00
Adjusted EBITDAX (b) $234.5 ‐ $280.0 $60.0 ‐ $70.0 $294.5 ‐ $350.0
Capital expenditures:
Drilling and completion $310.0 ‐ $345.0 $80.0 ‐ $85.0 $390.0 ‐ $430.0
Pipeline, gathering, facilities 17.0 ‐ 18.0 (2.5) ‐ (2.0) 14.5 ‐ 16.0
Seismic (c) 5.0 ‐ 7.0 (2.5) ‐ (2.0) 2.5 ‐ 5.0
Lease acquisitions, field projects and other 28.0 ‐ 30.0 (3.0) ‐ 1.0 25.0 ‐ 31.0
Total oil and gas capital expenditures $360.0 ‐ $400.0 $72.0 ‐ $82.0 $432.0 ‐ $482.0
(a) Assumes average benchmark prices of $90.96 per barrel for crude oil and $3.51 per MMBtu for natural gas, prior to any premium or discount for quality, basin differentials, the impact of hedges
and other adjustments. NGL realized pricing is assumed to be $29.38 per barrel.
(b) Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income. 27
(c) Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities .
