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Investor <strong>Presentation</strong><br />
IPAA OGIS New York<br />
April 2013<br />
NYSE: PVA<br />
0
Forward‐Looking Statements, Oil and Gas Reserves and Definitions<br />
Forward‐Looking Statements<br />
Certain statements contained herein that are not descriptions of historical facts are “forward‐looking” statements within the meaning of Section 27A of the Securities<br />
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,<br />
actual results may differ materially from those expressed or implied by such forward‐looking statements. These risks, uncertainties and contingencies include, but are<br />
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<br />
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<br />
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<br />
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<br />
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<br />
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<br />
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<br />
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<br />
compete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets and repay our debt; leasehold<br />
terms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of<br />
necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access<br />
adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or<br />
attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental<br />
regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international<br />
economic and political conditions; and other risks set forth in our filings with the Securities and Exchange Commission (SEC).<br />
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<br />
determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward‐looking statements,<br />
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<br />
forward‐looking statements, whether as a result of new information, future events or otherwise.<br />
Oil and Gas Reserves<br />
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<br />
“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<br />
reserve estimates provided in <strong>this</strong> presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not<br />
necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in<br />
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<br />
19087 (Attn: Investor Relations). You can also obtain <strong>this</strong> report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC’s website at www.sec.gov.<br />
Definitions<br />
Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty tobe<br />
economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulation<br />
before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the<br />
estimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are less certain to be recovered than proved<br />
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<br />
proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should be<br />
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<br />
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<br />
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<br />
accordingly is less certain.<br />
1
<strong>Penn</strong> <strong>Virginia</strong> <strong>Corporation</strong> Overview<br />
Company Overview<br />
• Domestic onshore E&P company with Eagle Ford focus<br />
• The past two years have been transformational, with<br />
portfolio transitioning to oil and liquids<br />
• Discontinued any material gas drilling<br />
• HBP natural gas reserves in East Texas, the Mid‐Continent<br />
and Mississippi<br />
• Executing a strategy of growth in oil and NGL rich plays<br />
• Successful drilling results in the Eagle Ford Shale – 117 wells<br />
on‐line (71 legacy PVA and 46 legacy MHR) (1)<br />
• Adding to Eagle Ford drilling inventory<br />
– Successful exploratory results in Lavaca County<br />
– Approximately 640 (420 net) drilling locations remaining<br />
currently (1)<br />
• Strategy has resulted in significant growth in EBITDAX and<br />
cash operating margins<br />
• Focused on improving liquidity<br />
• Cash plus revolver availability of $316MM at YE12 ($321MM<br />
pro forma (2) )<br />
• Leverage ratio (net) of 2.3x at YE12 (3.3x pro forma)<br />
• Over 69% of 2013 oil production (PVA stand‐alone) hedged<br />
at weighted average price of $96.67 per barrel (WTI)<br />
• Over 68% of 2013 gas production (PVA stand‐alone) hedged<br />
at weighted average price of $3.77 per MMBtu (HH)<br />
Financial and Operational Summary<br />
Financial Summary<br />
Common Equity Market Capitalization (4/2/2013) (3)<br />
$263MM<br />
Convertible Preferred (4)<br />
$115MM<br />
Equity Market Capitalization<br />
$378MM<br />
Operational Summary<br />
Pro Forma Production (5)<br />
2012 Q4 Average Daily Prod. (MBOEPD) 18.2<br />
February 2013 Production (MBOEPD) 19.5<br />
Pro Forma Proved Reserves (MMBOE) 125.5<br />
% Liquids 46%<br />
% Proved Developed 41%<br />
(1) Pro forma for the MHR acquisition as of April 3, 2013 (the “Acquisition”).<br />
(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<br />
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.<br />
(3) Reflects share price of $4.41 as of April 11, 2013; includes new common equity issuance in the amount of $40MM.<br />
(4) Net issue proceeds of convertible preferred at 6%.<br />
(5) Figure is pro forma for asset sales and acquisitions.<br />
2
Transformational Acquisition<br />
Greater scale: ~83,000 (54,000 net) Eagle Ford acres and substantial growth in oil production/revenue<br />
• Purchase price of approximately $400MM for<br />
40,565 (19,037 net) highly contiguous net acres<br />
in Gonzales and Lavaca Counties<br />
• Year‐end 2012 SEC proved reserves of 12.0<br />
MMBOE (1)<br />
– Oil = 90% of proved reserves<br />
– 37% proved developed<br />
• Year‐end 2012 SEC PV‐10 of $241MM (1)<br />
– PD PV‐10 of $156MM<br />
• Year‐end reserves include 44 proved<br />
developed locations and 51 locations booked<br />
as PUDs (1)<br />
• Expands existing footprint and acreage is largely<br />
adjacent to existing position<br />
• Acquired assets add up to 345 gross (169<br />
net) locations (2)<br />
ACREAGE<br />
MHR LEGACY<br />
PVA LEGACY<br />
OPERATOR<br />
EOG<br />
MAGNUM HUNTER<br />
PVA<br />
HUNT<br />
MARATHON<br />
Gonzales<br />
HUNT<br />
MRO<br />
PVA<br />
EOG<br />
MHR<br />
PVA<br />
Lavaca<br />
EOG<br />
DeWitt<br />
(1) As of December 31, 2012 per March 28, 2013 reserve report prepared by Cawley, Gillespie & Associates.<br />
(2) As of April 3, 2013.<br />
3
Transformational Acquisition (cont.)<br />
Acquisition Impacts to PVA’s Asset Profile<br />
Growth in Key Corporate Metrics as a Result of Acquisition<br />
Growth in Key Eagle Ford Metrics as a Result of Acquisition<br />
Proved<br />
Developed<br />
Reserves<br />
9%<br />
Proved<br />
Developed<br />
Reserves<br />
45%<br />
Total Proved<br />
Reserves<br />
11%<br />
Total Proved<br />
Reserves<br />
46%<br />
Total Proved Oil<br />
Reserves<br />
44%<br />
Total Proved Oil<br />
Reserves<br />
53%<br />
February 2013<br />
Daily Production<br />
20%<br />
February 2013<br />
Daily Production<br />
42%<br />
Net Inventory<br />
28%<br />
Net Inventory<br />
68%<br />
Net Acres<br />
10%<br />
Net Acres<br />
54%<br />
Acquisition Significantly Increases PVA’s Eagle Ford Position and Overall Scale in the Eagle Ford<br />
Note: Reserves as of 12/31/2012 . All other figures as of April 3, 2013 unless otherwise stated.<br />
4
Sources & Uses / Pro Forma Capitalization<br />
Sources<br />
($ in millions)<br />
New Senior Notes $775<br />
Equity Issuance (1) 40<br />
Total Sources $815<br />
Uses<br />
($ in millions)<br />
Acquisition Consideration $400<br />
Refinance 2016 Senior Notes 300<br />
Post Closing Adjustments (2) 43<br />
Premium on Tender (3) 18<br />
Estimated Fees and Expenses (4) 25<br />
Cash to Balance Sheet 29<br />
Total Uses $815<br />
Pro Forma Capitalization<br />
Eagle Ford Acq. PVA Pro Forma<br />
($ in millions) 12/31/2012 Adjustments 12/31/2012<br />
Cash and Cash Equivalents (5) $18 $29 $47<br />
Revolving Credit Facility (6) ‐ ‐ ‐<br />
10.375% Senior Notes due 2016 300 (300) ‐<br />
7.250% Senior Notes due 2019 300 ‐‐ 300<br />
New Senior Notes ‐ 775 775<br />
Total Debt $600 $475<br />
$1,075<br />
6% Convertible Preferred $115 ‐‐ $115<br />
Proved Reserves (MMBoe) 113.5 12.0 125.5<br />
% Oil 22% 90% 28%<br />
% Liquids 40% 96% 45%<br />
% Developed 41% 37% 41%<br />
Q4 2012 Production (MBoe/d) 15.4 2.7 18.2<br />
Proved R/P (Years) 20.1x 12.2x 18.9x<br />
PD R/P (Years) 8.3x 4.4x 7.8x<br />
PT Proved PV‐10% $692 $241 $933<br />
(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.<br />
(2) PVA estimate based on closing date of May 15, 2013.<br />
(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.<br />
(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<br />
issuance fee due to backstop.<br />
(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<br />
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.<br />
(6) As of March 31, 2013, PVA had $38MM outstanding under its revolving credit facility.<br />
5
Eagle Ford Shale Operators<br />
Eastern Volatile Oil Windows (1)<br />
Volatile Oil<br />
EFS Operators<br />
PVA<br />
MHR<br />
Hunt<br />
BHP<br />
CHK<br />
COG<br />
COP<br />
CRK<br />
CRZO<br />
EOG<br />
FST<br />
MRO<br />
MUR<br />
NFX<br />
PXD<br />
PXP<br />
SFY<br />
STO<br />
TLM<br />
Bexar<br />
San Antonio<br />
Atascosa<br />
Wilson<br />
Gonzales<br />
Goliad<br />
DeWitt<br />
Lavaca<br />
Victoria<br />
Condensate<br />
Rich Gas<br />
Texas<br />
McMullen<br />
Live Oak<br />
Note: Some EFS operators off map.<br />
(1) Based on latest company presentations, as well as industry publications. Some industry publication information may be out of date.<br />
Bee<br />
6
Expanded Eagle Ford Acreage Position<br />
• Net acreage by operator across entire Eagle Ford play<br />
• Operators’ disclosed acreage includes leaseholds outside volatile oil window<br />
• Approximately all of PVA’s leasehold is in the volatile oil window<br />
(Net acreage in thousands)<br />
90<br />
80<br />
70<br />
60<br />
341<br />
138<br />
118<br />
72<br />
67<br />
62<br />
60<br />
54 54 53<br />
50<br />
40<br />
40 39<br />
35<br />
30<br />
28 28<br />
24<br />
22<br />
20<br />
10<br />
9 7<br />
0<br />
BHP SN PXD ZAZA ROSE COG PXP PVA PF SFY CRZO FST GDP PVA CRK MTDR HK Aurora CXPO AXAS<br />
Source: Company investor presentations and SEC filings through April 3, 2013.<br />
7
PVA’s Pro Forma Eagle Ford Shale Position<br />
Sizeable Position in a Successful Portion of the Eastern Oil Window of the Eagle Ford Shale<br />
Premier Shale Oil & Liquids Play<br />
Nearby Operators<br />
PVA Pro Forma<br />
BHP Billiton<br />
ConocoPhillips<br />
EOG<br />
Forest<br />
Gonzales<br />
Marathon<br />
Pioneer<br />
Plains<br />
Statoil<br />
DeWitt<br />
Lavaca<br />
• 82,995 gross (≥54,057 net) acres in Gonzales and Lavaca<br />
Counties, TX (1)<br />
• Operator of 46,452 (32,410 net) acres in Gonzales ‐ 70% WI<br />
• Operator of 23,203 (15,148 net) acres in Lavaca ‐ 65% WI(1)<br />
• Non‐operator of 13,340 (6,499 net) acres in Gonzales ‐ 49% WI<br />
• Avg. IP/30‐day rates of 1,066/676 BOEPD<br />
• Gonzales type curve EUR of ≥400 MBOE (2)<br />
• Lavaca type curve EUR of ≥500 MBOE (2)<br />
• Proved reserves of 38.2 MMBOE at year‐end 2012, consisting<br />
of 82% oil, 10% NGLs and 8% gas<br />
• Proved PV‐10 at YE12 of $844MM ($551MM of PD value)<br />
• 117 (82.0 net) wells producing<br />
• Objective is to lower PVA well costs by at least 10‐15% in 2013<br />
• Up to 640 (420 net) remaining drilling locations<br />
• Initial positive down‐spacing tests of 3‐well pad in Gonzales<br />
County and 2 closely spaced MHR wells in Lavaca County<br />
• Includes over 300 infill locations<br />
• Rigs, infrastructure in place<br />
• Dedicated rigs and frac crew<br />
• Gas gathering and processing in place<br />
• Receiving premium LLS base pricing<br />
(1) Net acreage in Lavaca County is expected to increase due to non‐consents by our partner on initial wells in 17 drilling units.<br />
(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.<br />
8
Acquired Asset in Detail<br />
Total of 345 (169 net) locations across 40,565 (19,037 net) acres in Gonzales and Lavaca Counties<br />
Prospect Area<br />
Gross<br />
Acres<br />
Net Acres<br />
Average<br />
Royalty<br />
Peach Creek (MHR) 19,722 9,166 20%<br />
Peach Creek (Hunt JV) 13,340 6,499 20%<br />
Shiner (GeoSouthern JV) 4,674 2,119 20%<br />
Shiner 2,829 1,253 20%<br />
Total / Average 40,565 19,037 20%<br />
Prospect Area<br />
Producing<br />
Wells<br />
Gross Non‐<br />
Producing<br />
Locations<br />
Net Non‐<br />
Producing<br />
Locations<br />
Peach Creek (MHR) 27 149 73.1<br />
Peach Creek (Hunt JV) 15 121 60.5<br />
Shiner (GeoSouthern JV) 3 72 32.6<br />
Shiner 1 3 3.0<br />
Total 46 345 169.3<br />
9
Combined Position Post Acquisition<br />
Area<br />
Significant Eagle Ford Shale Acreage and Drilling Inventory<br />
• Due to both acquisitions and leasing efforts over the past two years, our acreage position is<br />
now 83,000 gross (~54,000 net) acres primarily in the volatile oil window (1)<br />
• We also have a multi‐year inventory of up to 640 (420 net) additional drilling locations<br />
• Successful down‐spacing testing has added over 300 potential infill locations to our inventory<br />
• Locations will vary over time in terms of lateral length, frac stages, spacing and geology<br />
• Recent successful wells in the southern and eastern portions of our Lavaca acreage have further “derisked”<br />
our inventory<br />
• Unitizations with other industry participants and continued leasing are expected to yield additional<br />
locations<br />
Producing<br />
Wells<br />
Remaining<br />
Locations<br />
Total Well<br />
Locations<br />
Gross<br />
Acreage<br />
Net Acres /<br />
Acreage (1) Location (2)<br />
PVA Gonzales 54 190 244 26,239 21,261 108<br />
PVA Lavaca 17 105 122 16,191 13,759 133<br />
MHR Acquired 46 345 391 40,565 19,037 104<br />
Pro Forma Total 117 640 757 82,995 54,057 110<br />
(% Change) 65% 117% 107% 96% 54%<br />
(1) Net acreage in Lavaca County is expected to increase due to non‐consents by our partner on initial wells in 17 drilling units.<br />
(2) Represents gross acres per location.<br />
10
Strong and Consistent Initial Production Rates<br />
Both PVA’s legacy assets and the acquired position have strong and repeatable results<br />
PVA Legacy Assets<br />
Acquired MHR Assets<br />
Gonzales Lavaca Gonzales Lavaca<br />
30‐Day Avg (BOEPD) IP (BOEPD) 30‐Day Avg (BOEPD) IP (BOEPD)<br />
• Average Gonzales IP / 30‐Day Rate of 921 / 621 BOEPD<br />
• Average Lavaca IP / 30‐Day Rate of 939 / 644 BOEPD<br />
• Gonzales Averages of 15 Stages and 3,713’ Lateral Length (LL)<br />
• Lavaca Averages of 19 Stages and 4,583’ LL<br />
• Average Gonzales IP / 30‐Day Rate of 1,065 / 678 BOEPD<br />
• Average Lavaca IP / 30‐Day Rate of 1,503 / 849 BOEPD<br />
• Gonzales Averages of 16 Stages and 4,605’ LL<br />
• Lavaca Averages of 22 Stages and 6,114’ LL<br />
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.<br />
11
Attractive Economics in Volatile Oil Window<br />
Compelling Economics & Value at Varying Oil Prices<br />
Gonzales County (1) Lavaca County (1)<br />
• Assumptions<br />
• Longer lateral lengths in 2013 vs. PUD assumption<br />
• 460 MBOE EUR type curve<br />
• Drilling and completion (D&C) costs per below<br />
Key Takeaways<br />
D&C of<br />
$9.1MM<br />
D&C of<br />
$8.1MM<br />
IRR 40 – 52% 52 – 76%<br />
BTAX PV‐10 (2) ($MM) $5.6 – 7.4 $6.6 –8.4<br />
Breakeven (3) ($/BOE) $47 – 57 $41 –52<br />
• Assumptions<br />
• Longer lateral lengths in 2013 vs. PUD assumption<br />
• 590 MBOE EUR type curve<br />
• Drilling and completion (D&C) costs per below<br />
Key Takeaways<br />
D&C of<br />
$10.1MM<br />
D&C of<br />
$9.1MM<br />
IRR 37 – 52% 50 – 71%<br />
BTAX PV‐10 (2) ($MM) $6.1 – 8.2 $7.1 –9.2<br />
Breakeven (3) ($/BOE) $47 – 57 $42 –52<br />
100<br />
GONZALES COUNTY<br />
Pretax Rate of Return Sensitivities<br />
100<br />
LAVACA COUNTY<br />
Pretax Rate of Return Sensitivities<br />
90<br />
$4.00/MMBtu Flat Gas Price<br />
90<br />
$4.00/MMBtu Flat Gas Price<br />
Rate of Return BFIT - %<br />
80<br />
70<br />
60<br />
50<br />
40<br />
30<br />
Rate of Return BFIT - %<br />
80<br />
70<br />
60<br />
50<br />
40<br />
30<br />
20<br />
20<br />
10<br />
10<br />
0<br />
40 50 60 70 80 90 100 110 120<br />
0<br />
40 50 60 70 80 90 100 110 120<br />
Base Case EUR = 460MBOE WTI (8/8ths) Oil Price (Flat) - $/Bbl Base Case EUR = 460MBOE (8/8ths)<br />
Capex = $9.1MM (8/8ths) LLS Pricing<br />
Capex = $9.1MM (8/8ths) WTI Pricing<br />
Sensitivity Case EUR = 460MBOE (8/8ths)<br />
Capex = $8.1MM (8/8ths) LLS Pricing<br />
Sensitivity Case EUR = 460MBOE (8/8ths)<br />
Capex = $8.1MM (8/8ths) WTI Pricing<br />
Base Case EUR = 590MBOE (8/8ths)<br />
Base Case EUR = 590MBOE (8/8ths)<br />
WTI Oil Price (Flat) - $/Bbl<br />
Capex = $10.1MM (8/8ths) LLS Pricing<br />
Capex = $10.1MM (8/8ths) WTI Pricing<br />
Sensitivity Case EUR = 590MBOE (8/8ths)<br />
Sensitivity Case EUR = 590MBOE (8/8ths)<br />
Capex = $9.1MM (8/8ths) LLS Pricing<br />
Capex = $9.1MM (8/8ths) WTI Pricing<br />
(1) Based on YE12 PUDs, excluding short‐length lateral wells, applied to longer length laterals in 2013 program.<br />
(2) Assuming a flat $90 per barrel WTI oil price.<br />
(3) Before tax PV‐10 breakeven WTI oil price.<br />
12
Revised 2013 Capital Plan<br />
2013 Capital Spending Focused on Eagle Ford Drilling<br />
• Full‐year 2013 capital expenditures expected to be approximately $457MM (1)<br />
• Four operated rigs with two on existing PVA acreage and two rigs on operated MHR acreage<br />
• Two non‐operated rigs<br />
• Incremental capital spending of approximately $77MM (1)<br />
• Six‐rig drilling program (currently seven rigs running between PVA, MHR and Hunt)<br />
• Adjusted EBITDAX expected to increase to between $295 and $350MM, or 25% over previous guidance<br />
• 2013 capital spending is expected to be 92% Eagle Ford<br />
• Maintenance and new ventures capital for other areas<br />
Pro Forma Capital Expenditures by Area (1) Pro Forma Capital Expenditures by Type (1) Other<br />
Acquired Eagle<br />
Ford Assets<br />
28%<br />
Other D&C<br />
4%<br />
Land<br />
5%<br />
Existing Eagle<br />
Ford<br />
64%<br />
Mid‐Continent<br />
3%<br />
Pearsall<br />
2%<br />
Other<br />
3%<br />
Eagle Ford D&C<br />
87%<br />
4%<br />
(1) Change in mid‐points of full‐year 2013 guidance, adjusted for acquired Eagle Ford assets.<br />
13
Acquisition’s Effect on Production Volumes and Mix<br />
Positive Production Trend<br />
• During 2011 and into early 2012, we quickly ramped up Eagle Ford Shale production, and<br />
expect to increase production once again during 2013<br />
• Approximately 94% of sales volumes are liquids ‐ primarily crude oil<br />
• Oil is sold into Gulf Coast LLS market through multiple purchasers at premium pricing to WTI<br />
Pre Acquisition Eagle Ford Production (MBOEPD)<br />
Post Acquisition Eagle Ford Production (MBOEPD)<br />
11.2<br />
7%<br />
$10<br />
$5<br />
6.4<br />
7%<br />
9%<br />
7.9<br />
8%<br />
8%<br />
$10<br />
$5<br />
8.5<br />
6%<br />
8%<br />
7%<br />
86%<br />
2.3<br />
84%<br />
85%<br />
2.3<br />
86%<br />
88%<br />
88%<br />
$0<br />
2011 2012 2013E<br />
$0<br />
2011 2012 PF 2013E<br />
Oil and Condensate NGLs Natural Gas<br />
14
Current Geographic Footprint<br />
Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays<br />
Eagle Ford and Other Regions<br />
Mid‐Continent<br />
Proved reserves: 12.5 MMBOE<br />
% Oil/NGLs: 47%<br />
% PD: 79%<br />
2012 Production: 1,211 MBOE<br />
Cotton Valley<br />
Proved reserves: 39.6 MMBOE<br />
% Oil/NGLs: 34%<br />
% PD: 34%<br />
2012 Production: 882 MBOE<br />
Haynesville<br />
Proved reserves: 17.2 MMBOE<br />
% Gas: 86%<br />
% PD: 26%<br />
2012 Production: 454 MBOE<br />
Appalachian Region<br />
Marcellus<br />
Proved reserves: 0.5 MMBOE<br />
% Gas: 100%<br />
% PD: 23%<br />
2012 Production: 43 MBOE<br />
Total Company<br />
Pro Forma Eagle Ford<br />
Proved reserves: 38.2 MMBOE<br />
% Oil/NGLs: 92%<br />
% PD: 37%<br />
2012 Production: 3,092 MBOE<br />
Selma Chalk<br />
Proved reserves: 17.6 MMBOE<br />
% Gas: 99%<br />
% PD: 54%<br />
2012 Production: 847 MBOE<br />
Pro Forma <strong>Penn</strong> <strong>Virginia</strong><br />
Proved reserves: 125.5 MMBOE<br />
% Oil/NGLs: 46%<br />
% PD: 41%<br />
2012 Production: 6,529 MBOE (1)<br />
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.<br />
(1) Excludes divested production.<br />
15
Pro Forma Total Company Drilling Inventory<br />
Pro Forma PVA Has a Healthy Inventory of Drilling Locations<br />
• Total inventory of up to 1,133 gross undrilled locations (952 horizontal locations)<br />
• Up to 692 gross horizontal drilling locations in the Eagle Ford and Granite Wash<br />
• Significant upside in inventory of “gassy” locations<br />
Play<br />
Gross Undrilled<br />
Locations<br />
Average Working<br />
Interest<br />
Gross EUR<br />
(MBOE/Well) (1)<br />
Existing Eagle Ford (Gonzales) 190 83% 394<br />
Existing Eagle Ford (Lavaca) 105 88% 513<br />
Acquired MHR Assets 345 48% 385<br />
Granite Wash 52 18% 809<br />
Cotton Valley 78 71% 903<br />
Haynesville 78 77% 869<br />
Cotton Valley (vertical) 181 71% 172<br />
Selma Chalk 104 96% 302<br />
Totals 1,133<br />
Note: Latest through April 3, 2013; excludes two Marcellus locations.<br />
(1) Median gross EUR for all PUD locations.<br />
16
Regional / Play Production Breakout<br />
Expanding Production Volumes from Eagle Ford Assets<br />
Production Volumes by Operating Region (MMBOE)<br />
• Eagle Ford production<br />
growth is PVA’s focus<br />
going forward<br />
• Production volumes<br />
in the Eagle Ford are<br />
expanding from pro<br />
forma 40% in 2012 to<br />
at least 60% in 2013<br />
6.2<br />
14%<br />
12%<br />
18%<br />
(1)<br />
5.8<br />
40%<br />
8%<br />
(1)<br />
6.8<br />
18%<br />
42%<br />
35%<br />
21%<br />
15%<br />
5%<br />
10%<br />
21%<br />
14%<br />
15% 11%<br />
(1)<br />
2011 2012 2013E<br />
Cotton Valley Mid‐Continent Selma Chalk<br />
Marcellus Haynesville PVA Legacy Eagle Ford<br />
Acquired MHR Eagle Ford<br />
(1)<br />
Note: 2013 annual production guidance of 6,518 MBOE – 7,175 MBOE, midpoint of 6,847 MBOE.<br />
(1) Excludes divested production.<br />
17
Increasing Liquids Production<br />
• Since 2011, PVA has consistently grown its<br />
annual liquids production<br />
Production Mix Over Time<br />
• The Acquisition will significantly increase<br />
liquids production and overall production<br />
growth<br />
52%<br />
47%<br />
33%<br />
• In 2013, 92% of PVA’s capex program will be<br />
allocated to the Eagle Ford<br />
72%<br />
12%<br />
• Expected to run six rigs in 2013, post<br />
acquisition<br />
14%<br />
13%<br />
• Shift in liquids focused production has resulted<br />
in 2012 pro forma production being 53%<br />
liquids<br />
• 40% oil and 13% NGLs<br />
12%<br />
17%<br />
35%<br />
40%<br />
55%<br />
2011 2012 2012 PF 2013E<br />
Oil & Condensate NGLs Natural Gas<br />
Note: 2013 annual crude oil and NGLs production mix guidance of 64.5% ‐ 69.4%.<br />
18
Oil Based Strategy Continues<br />
• PVA has significantly increased its liquids percentage of revenue since the beginning of 2011<br />
Annual Product Revenue by Commodity (Before Hedges)<br />
Annual EBITDAX<br />
$425<br />
$322<br />
$400<br />
$300<br />
$248<br />
$300<br />
$310<br />
$220<br />
16%<br />
$200<br />
46%<br />
10%<br />
$200<br />
89%<br />
Liquids<br />
14%<br />
74%<br />
$100<br />
40%<br />
$0<br />
2011 2012 2013E<br />
$0<br />
2011 2012 2013E<br />
Oil NGL Gas<br />
Note: 2013E based on the mid‐point of updated guidance and price deck for 2013: ($90.96 / $3.51).<br />
19
Operating Margins<br />
• PVA has consistently increased<br />
cash margin since 2011 through:<br />
• Investment in higher rate‐ofreturn<br />
oil projects<br />
• Advantaged LLS pricing<br />
• Decreasing per unit operating<br />
costs<br />
• The Acquisition is expected to<br />
further expand cash margins<br />
$70<br />
$60<br />
$50<br />
$40<br />
$30<br />
$20<br />
Unhedged Cash Margin Over Time ($/BOE)<br />
$52.62<br />
$47.67<br />
$4.58<br />
$2.00<br />
$5.11<br />
$1.95<br />
$38.70<br />
$1.63<br />
$2.18<br />
$5.13<br />
$5.28<br />
$4.80<br />
$1.74<br />
$1.98<br />
$4.74<br />
$38.96<br />
$33.95<br />
$62.02<br />
$6.12<br />
$4.25<br />
$1.55<br />
$4.85<br />
$45.25<br />
Realized<br />
Price<br />
Cash<br />
Margin<br />
$24.96<br />
$10<br />
$0<br />
2011 2012 2012 PF 2013E<br />
Cash Margin<br />
G&P and transportation<br />
Cash G&A (excludes share‐based compensation)<br />
LOE<br />
Production taxes<br />
Note:<br />
Cash margin ($ / BOE) is defined as total product revenues, excluding the impact of hedges, less direct operating expenses per unit of equivalent production.<br />
Assumed price deck for 2013: ($90.96 / $3.51).<br />
20
Strong Margins vs. Peers<br />
• EBITDAX has increased significantly since mid‐2010 when we shifted our strategy to oil and NGLs<br />
• Cash margin per BOE has also improved significantly due to the increase in oil prices and<br />
declining operating costs per unit<br />
• Eagle Ford cash margin was $79.00 / BOE in 4Q12 (1)<br />
Quarterly Adjusted EBITDAX and EBITDAX Margin ($ / BOE)<br />
Comparative Q4 2012 EBITDAX Margins ($ / BOE) (2)<br />
$70<br />
$66<br />
$62<br />
$64<br />
$61<br />
$60<br />
$62<br />
$48.41<br />
$45.88<br />
$43.72<br />
$49<br />
$46 $45<br />
$44<br />
$48<br />
$33.01<br />
$34.77<br />
$35.44<br />
$34.51<br />
$39.73<br />
$43.72<br />
$40.61<br />
$39.10<br />
$36.48<br />
$28.50<br />
$33<br />
$20.73<br />
$20.76<br />
$21.72<br />
$24.38<br />
$26.37<br />
$25.01 $24.54<br />
$22.95<br />
$19.79<br />
$18.91<br />
$13.56<br />
$0<br />
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12<br />
PVA<br />
PF<br />
GDP PVA CWEI CRZO FST PDCE BBG CRK Antero XCO KWK<br />
Source: Company filings.<br />
(1) Excludes regional and corporate G&A expenses.<br />
(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<br />
disclosed. Inclusive of realized hedge gains or losses.<br />
(3) Pro forma for the Acquisition.<br />
(3)<br />
21
Hedging Strategy<br />
Protect Cash Flow<br />
• Maintain an active hedging program to help support capital spending program and ensure strong<br />
coverage metrics<br />
• Hedges in place to protect cash flow<br />
• Natural gas hedging is currently 68% of expected 2013 total volumes at an average floor price of $3.77 / Mcf<br />
• Oil hedging is currently 69% of expected 2013 total volumes at an average floor price of $96.67 / barrel<br />
– 35% hedged for 2014 (stand‐alone) of total volumes at $94.87 / barrel<br />
• Upon closing the acquisition we will enter into additional hedges and expect the overall percent<br />
of production hedged to closely resemble our current levels<br />
Crude Oil Hedges (Swaps and Collars) (1)<br />
Natural Gas Hedges (Swaps and Collars) (1)<br />
Barrels per Day<br />
7,000<br />
6,000<br />
5,000<br />
4,000<br />
3,000<br />
2,000<br />
1,000<br />
0<br />
$102<br />
$98<br />
$101<br />
$97<br />
$99 $99<br />
$96 $96<br />
Weighted Average Ceiling /<br />
Swap Price by Quarter<br />
$95<br />
$95<br />
Weighted Average Floor /<br />
Swap Price by Quarter<br />
$94 $94<br />
1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14<br />
$110<br />
$105<br />
$100<br />
$95<br />
$90<br />
$85<br />
$80<br />
$75<br />
Weighted Avg. Floors and Swaps ($/Bbl)<br />
MMBtu per Day (000s)<br />
30<br />
25<br />
20<br />
15<br />
10<br />
5<br />
0<br />
Weighted Average Ceiling /<br />
Swap Price by Quarter<br />
$4.16 $4.07 $4.07<br />
$3.76 $3.75 $3.75 $3.82<br />
$4.24 $4.27<br />
$4.02<br />
$4.03 $4.03<br />
Weighted Average Floor /<br />
Swap Price by Quarter<br />
1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14<br />
$6<br />
$5<br />
$4<br />
$3<br />
$2<br />
$1<br />
$0<br />
Weighted Avg. Floors and Swaps ($/MMBtu)<br />
(1) As of 3/25/13.<br />
22
Investment Highlights<br />
• Transformational acquisition increases footprint<br />
in the volatile oil window core of the Eagle Ford<br />
• With 82,995 gross (54,057 net) of highly<br />
contiguous acres, our pro forma position will be<br />
significant with attractive leverage on a per share<br />
basis<br />
ACREAGE<br />
MHR LEGACY<br />
PVA LEGACY<br />
OPERATOR<br />
EOG<br />
MAGNUM HUNTER<br />
PVA<br />
HUNT<br />
MARATHON<br />
MHR<br />
• MHR’s acreage is adjacent to our current position<br />
with similar geologic and reserve characteristics<br />
to our current Eagle Ford assets<br />
• Enhances production growth, with 2013E<br />
production (7.5 months) of approximately 5,500<br />
BOEPD, representing a 34% increase (23%<br />
increase in BOEPD on a full‐year basis)<br />
Gonzales<br />
HUNT<br />
PVA<br />
EOG<br />
PVA<br />
• Increases drilling inventory in the Eagle Ford<br />
Shale to 640 (420 net) locations<br />
MRO<br />
• Attractive drilling economics with PV‐10<br />
breakeven WTI prices of $47 ‐ $57 per barrel<br />
Lavaca<br />
• 11% increase in proved reserves by adding 12.0<br />
MMBOE (96% liquids / 37% PD), increases Eagle<br />
Ford Shale proved reserve base by 46%<br />
EOG<br />
DeWitt<br />
23
Appendix<br />
24
Transaction Overview<br />
Transformational<br />
Acquisition in the<br />
Eagle Ford Shale<br />
Attractive<br />
Transaction<br />
Valuation<br />
Acquisition and<br />
Tender Offer<br />
Financing<br />
Closing Timeline<br />
• <strong>Penn</strong> <strong>Virginia</strong> is acquiring Eagle Ford Shale assets from Magnum Hunter for approximately $400MM<br />
• Assets are adjacent to PVA’s current Eagle Ford position in Gonzales and Lavaca Counties<br />
• 40,565 (19,037 net) acres in Gonzales and Lavaca counties<br />
• 46 (22.1 net) producing wells and drilling inventory of 345 (169 net) locations (1)<br />
• Approximately 3,173 BOEPD –February 2013<br />
• Approximately 5,500 BOEPD – 2013E (final eight months)<br />
• 12.0 MMBOE of proved reserves (37% PD / 96% Liquids) (2)<br />
• Transaction Value / Production ($ / BOEPD –February 2013) = ~$126,000<br />
• Transaction Value / Production ($ / BOEPD – 2013E) = ~$73,000<br />
• Transaction Value / Proved Reserves ($ / BOE) = ~$33.00<br />
• Transaction Value / 2013E EBITDAX ($93MM over 7.5 months, annualized) = ~2.7x<br />
• We have priced $775MM of 8.50% senior unsecured notes due 2020 in a private placement<br />
• Up to $330MM for tender offer for $300MM of 10.375% senior notes due 2016 @ 106%<br />
• At least $400MM to fund the MHR acquisition<br />
• Up to $40MM common equity option to issue up to 10MM shares to MHR @ $4/share<br />
• April 2 nd –PSA signed<br />
• April 2 nd – Acquisition announced<br />
• April 3 rd – Commence private placement<br />
• April 10 th –Price upsized notes private placement<br />
• By mid‐May 2013 –Close acquisition<br />
(1) Inventory as of April 3, 2013 includes seven MHR/Hunt wells that are in the process of completion or waiting on completion.<br />
(2) As of December 31, 2012 per March 28, 2013 reserve report prepared by Cawley, Gillespie & Associates.<br />
25
Pro Forma Reserves, PV‐10 and Production by Region / Play<br />
Proved Reserves (125.5 MMBOE)<br />
Haynesville<br />
14%<br />
Selma Chalk<br />
14%<br />
Mid‐Continent<br />
10%<br />
Marcellus<br />
0% PVA Legacy<br />
Eagle Ford<br />
21%<br />
Acquired MHR<br />
Eagle Ford<br />
10%<br />
Proved Developed Reserves (51.4 MMBOE)<br />
Haynesville<br />
9%<br />
Mid‐Continent<br />
19%<br />
Marcellus<br />
0% PVA Legacy<br />
Eagle Ford<br />
19%<br />
Acquired MHR<br />
Eagle Ford<br />
9%<br />
Cotton Valley<br />
32%<br />
Selma Chalk<br />
18%<br />
Cotton Valley<br />
26%<br />
Pre‐Tax PV‐10 ($933.2MM) (1)<br />
2012 Production (17.8 MBOEPD)<br />
Mid‐Continent<br />
11%<br />
Selma Chalk<br />
2%<br />
Cotton Valley<br />
1%<br />
Acquired MHR<br />
Eagle Ford<br />
26%<br />
PVA Legacy<br />
Eagle Ford<br />
65%<br />
Haynesville<br />
7%<br />
Mid‐Continent<br />
18%<br />
Marcellus<br />
1%<br />
PVA Legacy<br />
Eagle Ford<br />
36%<br />
Selma Chalk<br />
13%<br />
(1) Based on SEC pricing.<br />
Cotton Valley<br />
13%<br />
Acquired MHR<br />
Eagle Ford<br />
12%<br />
26
Full‐Year 2013 Guidance Table<br />
Revised for Proposed MHR Acquisition Assuming 5/15/13 Closing Date<br />
Current Full‐Year<br />
2013 Guidance<br />
Adjustments for MHR<br />
Acquisition / One Less Rig<br />
Pro Forma<br />
2013 Guidance<br />
Production:<br />
Crude oil (MBbls) 2,775 ‐ 3,075 760 ‐ 890 3,535 ‐ 3,965<br />
NGLs (MBbls) 730 ‐ 820 55 ‐ 75 785 ‐ 895<br />
Natural gas (MMcf) 13,000 ‐ 13,650 190 ‐ 240 13,190 ‐ 13,890<br />
Equivalent production (MBOE) 5,672 ‐ 6,170 847 ‐ 1,005 6,518 ‐ 7,175<br />
Equivalent daily production (BOEPD) 15,539 ‐ 16,904 3,681 ‐ 4,370 17,858 ‐ 19,658<br />
Percent crude oil and NGLs 59.9% ‐ 64.9% 95.3% ‐ 96.8% 64.5% ‐ 69.4%<br />
Production revenues (a):<br />
Crude oil $265.0 ‐ $293.5 $70.0 ‐ $80.0 $335.0 ‐ $373.5<br />
NGLs 21.5 ‐ 24.5 1.5 ‐ 2.0 23.0 ‐ 26.5<br />
Natural gas 43.5 ‐ 45.5 1.0 ‐ 1.5 44.5 ‐ 47.0<br />
Total product revenues $330.0 ‐ $363.5 $72.5 ‐ $83.5 $402.5 ‐ $447.0<br />
Total product revenues ($ per BOE) $58.18 ‐ $58.91 $85.63 ‐ $83.08 $61.75 ‐ $62.30<br />
Percent crude oil and NGLs 86.2% ‐ 88.0% 97.9% ‐ 98.8% 88.3% ‐ 90.0%<br />
Operating expenses:<br />
Lease operating ($ per BOE) $4.60 ‐ $5.00 $4.65 ‐ $5.05<br />
Gathering, processing and trans. costs ($ per BOE) $1.70 ‐ $1.90 $1.45 ‐ $1.65<br />
Production and ad valorem taxes (% of oil and gas revenues) 6.3% ‐ 6.9% 6.6% ‐ 7.1%<br />
General and administrative:<br />
Recurring general and administrative $39.5 ‐ $40.5 $1.8 ‐ $2.0 $41.3 ‐ $42.5<br />
Share‐based compensation 3.0 ‐ 4.0 0.2 ‐ 0.3 3.2 ‐ 4.3<br />
Restructuring 2.5 ‐ 2.7 2.5 ‐ 2.7<br />
Total reported G&A $42.5 ‐ $44.5 $4.5 ‐ $5.0 $47.0 ‐ $49.5<br />
Exploration:<br />
Total reported exploration $28.0 ‐ $30.0 $18.0 ‐ $22.0 $46.0 ‐ $52.0<br />
Unproved property amortization 21.0 ‐ 22.0 21.0 ‐ 24.0 42.0 ‐ 46.0<br />
Depreciation, depletion and amortization ($ per BOE) $36.00 ‐ $39.00 $36.00 ‐ $39.00<br />
Adjusted EBITDAX (b) $234.5 ‐ $280.0 $60.0 ‐ $70.0 $294.5 ‐ $350.0<br />
Capital expenditures:<br />
Drilling and completion $310.0 ‐ $345.0 $80.0 ‐ $85.0 $390.0 ‐ $430.0<br />
Pipeline, gathering, facilities 17.0 ‐ 18.0 (2.5) ‐ (2.0) 14.5 ‐ 16.0<br />
Seismic (c) 5.0 ‐ 7.0 (2.5) ‐ (2.0) 2.5 ‐ 5.0<br />
Lease acquisitions, field projects and other 28.0 ‐ 30.0 (3.0) ‐ 1.0 25.0 ‐ 31.0<br />
Total oil and gas capital expenditures $360.0 ‐ $400.0 $72.0 ‐ $82.0 $432.0 ‐ $482.0<br />
(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<br />
and other adjustments. NGL realized pricing is assumed to be $29.38 per barrel.<br />
(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.<br />
(c) Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities .<br />
27
Production and Revenue Metrics<br />
4Q 2012 Oil Production Mix<br />
4Q 2012 Unhedged Oil Revenue (% of Revenue)<br />
1<br />
1<br />
1<br />
0<br />
68%<br />
65%<br />
47%<br />
39%<br />
1<br />
1<br />
1<br />
1<br />
1<br />
87%<br />
86%<br />
79%<br />
76%<br />
73% 72%<br />
68%<br />
61%<br />
36% 35%<br />
30%<br />
49% 47%<br />
38%<br />
0<br />
0<br />
0<br />
0<br />
CWEI Aurora PVA<br />
PF<br />
27%<br />
18 %<br />
4Q 2012 Average Realized Price (Unhedged)<br />
17% 16 %<br />
2% 1% 0%<br />
PVA SFY CRZO GDP PDCE BBG FST CRK XCO KWK Antero<br />
0<br />
0<br />
0<br />
0<br />
0<br />
CWEI Aurora PVA<br />
PF<br />
CRZO PVA SFY GDP PDCE CRK FST BBG XCO KWK Antero<br />
4Q 2012 Cash Margin (Unhedged)<br />
9%<br />
5%<br />
1%<br />
80<br />
60<br />
$72.37<br />
$66.94<br />
$59.14<br />
$80<br />
$70<br />
$60<br />
$72.37<br />
$66.94<br />
$59.14<br />
Cash M argin<br />
Cash G&A<br />
Tot al Production Expenses<br />
$53.49<br />
$50.85<br />
$45.19 $43.41<br />
$36.06 $36.05<br />
$50<br />
40<br />
$40<br />
34.50<br />
39.30<br />
$30<br />
20<br />
$32.65<br />
$30.03<br />
$22.23 $21.91 $20.78<br />
$20<br />
8.26<br />
$53.49<br />
$50.86<br />
$45.19 $43.41<br />
$36.06 $36.05<br />
$32.65<br />
$30.03<br />
$22.23 $21.91 $20.78<br />
0<br />
Aurora CWEI PVA<br />
PF<br />
PVA SFY CRZO GDP PDCE BBG FST CRK Antero KWK XCO<br />
$10<br />
$0<br />
16 .3 9<br />
Aurora CWEI PVA<br />
PF<br />
5.82<br />
8.37<br />
PVA SFY CRZO GDP PDCE BBG FST CRK Antero KWK XCO<br />
Source: Public filings and investors presentations. <strong>Penn</strong> <strong>Virginia</strong> pro forma for the Acquisition.<br />
28
Operational and Reserve Metrics<br />
3‐Year F&D Costs, Drill‐bit ($ / BOE) (2)<br />
$43.34 $43.25<br />
$25.96<br />
$40<br />
$25<br />
$34.14<br />
$30<br />
$20<br />
$19.37 $19.30 $18.63<br />
$14.92 $13.85<br />
$11.36 $11.34 $10.91 $10.71<br />
$5.21<br />
$26.37 $25.47<br />
$23.13<br />
$19.53 $17.65 $17.08 $15.30<br />
$3.74<br />
$15<br />
$20<br />
$10<br />
$10<br />
$2.61<br />
$5<br />
$1.73<br />
$0<br />
KWK GDP CRZO XCO BBG CRK PVA CWEI FST SFY PDCE Antero<br />
2012 Reserve Replacement, Total (3)<br />
$0<br />
CRZO GDP BBG PVA CWEI FST CRK SFY XCO KWK PDCE Antero<br />
2012 Proved Reserves (MMBOE) (4)<br />
600%<br />
2243% 1226%<br />
542%<br />
200<br />
180<br />
821.7<br />
192.1<br />
183.4 181.8 178.7<br />
174.0<br />
450%<br />
428%<br />
374%<br />
160<br />
140<br />
120<br />
125.5<br />
118.0 115.1<br />
300%<br />
281%<br />
100<br />
91.8<br />
150%<br />
194%<br />
1‐Year F&D Costs, Drill‐bit ($ / BOE) (1) 29<br />
161% 140%<br />
101%<br />
54%<br />
37%<br />
80<br />
60<br />
40<br />
20<br />
75.4<br />
55.5<br />
0%<br />
Antero PDCE CRZO CWEI SFY PVA FST BBG CRK GDP XCO KWK<br />
Note: CRZO metrics represent U.S. assets only.<br />
(1) 1‐Year F&D costs calculated by dividing the sum of 2012 exploration, production and development costs by the sum of extensions, discoveries and improved recovery of proved reserves.<br />
(2) 3‐Year F&D costs calculated by dividing the sum of exploration, production and development costs by the sum of extensions, discoveries and improved recovery of proved reserves over the<br />
period from 2010 to 2012.<br />
(3) Reserve replacement calculated by taking the sum of purchases, extensions, discoveries and improved recovery of proved reserves by annual production.<br />
(4) Pro forma for all recently announced transactions, including with respect to PVA, the Acquisition.<br />
0<br />
Antero SFY KWK FST PDCE BBG PVA PF XCO CRZO CRK CWEI GDP
Non‐GAAP Reconciliation<br />
Adjusted EBITDAX<br />
Year ended December 31,<br />
2008 2009 2010 2011 2012<br />
dollars in millions<br />
Net income (loss) from continuing operations $ 93.6 $ (130.9) $ (65.3) $ (132.9) $ (104.6)<br />
Add: Income tax expense (benefit) 55.6 (85.9) (42.9) (88.2) (68.7)<br />
Add: Interest expense 24.6 44.2 53.7 56.2 59.3<br />
Add: Depreciation, depletion and amortization 135.7 154.4 134.7 162.5 206.3<br />
Add: Exploration 42.4 57.8 49.6 78.9 34.1<br />
Add: Share‐based compensation expense 6.0 9.1 7.8 7.4 6.3<br />
Add/Less: Derivatives (income) expense included in net income (29.7) (31.6) (41.9) (15.7) (36.2)<br />
Add/Less: Cash receipts (payments) to settle derivatives (7.6) 58.1 32.8 27.4 29.7<br />
Add/Less: Loss on firm transportation commitment ‐ ‐ ‐ ‐ 17.3<br />
Add: Impairments 20.0 106.4 46.0 104.7 104.5<br />
Add/Less: Net loss (gain) on sale of assets, other (33.2) (2.0) (1.2) 22.0 (0.6)<br />
Adjusted EBITDAX $ 307.4 $ 179.7 $ 173.3 $ 222.5 $ 247.6<br />
30
<strong>Penn</strong> <strong>Virginia</strong> <strong>Corporation</strong><br />
4 Radnor Corporate Center, Suite 200<br />
Radnor, PA 19087<br />
610‐687‐8900<br />
www.pennvirginia.com