PVA IPAA OGIS NY

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PVA IPAA OGIS NY

  1. 1. Investor PresentationIPAA OGIS New YorkApril 2013NYSE: PVA 0
  2. 2. Forward‐Looking Statements, Oil and Gas Reserves and DefinitionsForward‐Looking StatementsCertain statements contained herein that are not descriptions of historical facts are “forward‐looking” statements within the meaning of Section 27A of the SecuritiesAct 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 arenot limited to, the following: our ability to successfully complete the acquisition of Eagle Ford Hunter, Inc. (“MHR”), as described herein, integrate the business of MHRwith ours and realize the anticipated benefits from the acquisition; any unexpected costs or delays in connection with the acquisition of MHR; the volatility ofcommodity 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; ourability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write‐downs or write‐offs ofour 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 creditfacility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil andgas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates ofproduction for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability tocompete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets and repay our debt; leaseholdterms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt ofnecessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to accessadequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain orattract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmentalregulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and internationaleconomic 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 willdetermine 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 otherforward‐looking statements, whether as a result of new information, future events or otherwise.Oil and Gas ReservesEffective 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. Anyreserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves notnecessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure inPVA’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, PA19087 (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.DefinitionsProved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to beeconomically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulationbefore the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether theestimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are less certain to be recovered than provedreserves, 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 theproved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should beat least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). “3P” reserves referto 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 productionas 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 andaccordingly is less certain. 1
  3. 3. Penn Virginia Corporation OverviewCompany 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. 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 $156MM • Year‐end reserves include 44 proved  developed locations and 51 locations booked  PVA EOG as PUDs(1) • Expands existing footprint and acreage is largely  MRO adjacent to existing position Lavaca • Acquired assets add up to 345 gross (169 net) locations(2) EOG DeWitt 3(1) As of December 31, 2012 per March 28, 2013 reserve report prepared by Cawley, Gillespie & Associates.(2) As of April 3, 2013.
  5. 5. Transformational Acquisition (cont.) Acquisition Impacts to PVA’s Asset Profile Growth in Key Corporate Metrics as a Result of Acquisition Growth in Key Eagle Ford Metrics as a Result of Acquisition Proved Proved Devel oped 9% Devel oped 45% Res erves Res erves Tota l  Proved Tota l  Proved 11% 46% Res erves Res erves Tota l  Proved Oi l Tota l  Proved Oil Res erves 44% 53% Res erves Februa ry 2013 Februa ry 2013 Da i l y Producti on 20% 42% Da il y Producti on Net Inventory 28% Net Inventory 68% Net Acres 10% Net Acres 54% Acquisition Significantly Increases PVA’s Eagle Ford Position and Overall Scale in the Eagle Ford 4Note: Reserves as of 12/31/2012 . All other figures as of April 3, 2013 unless otherwise stated.
  6. 6. Sources & Uses / Pro Forma CapitalizationSources ($ in millions) Pro Forma CapitalizationNew 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 ‐‐ 300Pos t Cl os i ng Adjus tments (2) 43 New Seni or Notes ‐ 775 775Premi um on Tender(3) 18 Tota l  Debt $600 $475 $1,075Es ti ma ted Fees  a nd Expens es (4) 25Ca s h to Ba l a nce Sheet 29 6% Converti bl e Preferred $115 ‐‐ $115Total 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. 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 OakNote: 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. 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 34190 138 11880 7270 67 62 6060 54 54 5350 40 3940 3530 28 28 24 222010 9 7 0 BHP SN PXD ZAZA ROSE COG PXP PVA PF SFY CRZO FST GDP PVA CRK MTDR HK Aurora CXPO AXASSource: Company investor presentations and SEC filings through April 3, 2013.  7
  9. 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. 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. 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. 12. Strong and Consistent Initial Production Rates Both PVA’s legacy assets and the acquired position have strong and repeatable resultsPVA 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’ LLNote: 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. 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. 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. 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. 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. 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 1,133Note: Latest through April 3, 2013; excludes two Marcellus locations. 16(1)  Median gross EUR for all PUD locations.
  18. 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 FordNote:  2013 annual production guidance of 6,518 MBOE – 7,175 MBOE, midpoint of 6,847 MBOE.(1) Excludes divested production. 17
  19. 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 GasNote:  2013 annual crude oil and NGLs production mix guidance of 64.5% ‐ 69.4%. 18
  20. 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 19Note: 2013E based on the mid‐point of updated guidance and price deck for 2013: ($90.96 / $3.51).
  21. 21. Operating Margins Unhedged Cash Margin Over Time ($/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. 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. 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. 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
  25. 25. Appendix 24
  26. 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. 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. 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 . 

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