Published on

Published in: Business, Economy & Finance
  • Be the first to comment

  • Be the first to like this

No Downloads
Total views
On SlideShare
From Embeds
Number of Embeds
Embeds 0
No embeds

No notes for slide


  1. 1. 0Investor PresentationIPAA OGIS New YorkApril 2013NYSE: PVA
  2. 2. 1Forward‐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.
  3. 3. 2Financial and Operational SummaryPenn Virginia Corporation OverviewCompany OverviewFinancial SummaryCommon Equity Market Capitalization (4/2/2013)(3)Convertible Preferred(4)Equity Market Capitalization$263MM$115MM$378MMOperational SummaryPro Forma Production(5)2012 Q4 Average Daily Prod. (MBOEPD)  18.2February 2013 Production (MBOEPD) 19.5Pro Forma Proved Reserves (MMBOE) 125.5% Liquids 46%% Proved Developed 41%• Domestic onshore E&P company with Eagle Ford focus• The past two years have been transformational, with portfolio transitioning to oil and liquids• Discontinued any material gas drilling• HBP natural gas reserves in East Texas, the Mid‐Continent and Mississippi• 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)• Adding to Eagle Ford drilling inventory – Successful exploratory results in Lavaca County– Approximately 640 (420 net) drilling locations remaining currently(1)• Strategy has resulted in significant growth in EBITDAX and cash operating margins• Focused on improving liquidity• Cash plus revolver availability of $316MM at YE12 ($321MM pro forma(2))• Leverage ratio (net) of 2.3x at YE12 (3.3x pro forma)• 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%.(5) Figure is pro forma for asset sales and acquisitions.
  4. 4. 3• Purchase price of approximately $400MM for 40,565 (19,037 net) highly contiguous net acres in Gonzales and Lavaca Counties• Year‐end 2012 SEC proved reserves of 12.0 MMBOE(1)– Oil = 90% of proved reserves – 37% proved developed• Year‐end 2012 SEC PV‐10 of $241MM(1)– PD PV‐10 of $156MM• Year‐end reserves include 44 proved developed locations and 51 locations booked as PUDs(1)• Expands existing footprint and acreage is largely adjacent to existing position• Acquired assets add up to 345 gross (169net) locations(2)Greater scale: ~83,000 (54,000 net) Eagle Ford acres and substantial growth in oil production/revenueTransformational AcquisitionMROMHRPVAHUNTEOGEOGPVAGonzalesLavacaDeWittACREAGEMHR LEGACYPVA LEGACYOPERATOREOGMAGNUM HUNTERPVAHUNTMARATHON(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. 410%28%44%11%9%20%Net AcresNet InventoryFebruary 2013Daily ProductionTotal Proved OilReservesTotal ProvedReservesProvedDevelopedReserves54%68%53%46%45%42%Net AcresNet InventoryFebruary 2013Daily ProductionTotal Proved OilReservesTotal ProvedReservesProvedDevelopedReservesAcquisition Impacts to PVA’s Asset ProfileTransformational Acquisition (cont.)Growth in Key Corporate Metrics as a Result of Acquisition Growth in Key Eagle Ford Metrics as a Result of AcquisitionAcquisition Significantly Increases PVA’s Eagle Ford Position and Overall Scale in the Eagle FordNote: Reserves as of 12/31/2012 . All other figures as of April 3, 2013 unless otherwise stated.
  6. 6. 5Sources & Uses / Pro Forma Capitalization(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.(6) As of March 31, 2013, PVA had $38MM outstanding under its revolving credit facility.Sources ($ in millions)New Senior Notes $775Equity Issuance(1)40Total Sources $815Uses ($ in millions)Acquisition Consideration $400Refinance 2016 Senior Notes 300Post Closing Adjustments(2)43Premium on Tender(3)18Estimated Fees and Expenses(4)25Cash to Balance Sheet 29Total Uses $815Pro Forma Capitalization($ in millions) 12/31/2012Eagle Ford Acq.AdjustmentsPVA Pro Forma 12/31/2012Cash and Cash Equivalents(5)$18 $29 $47Revolving Credit Facility(6)‐ ‐ ‐10.375% Senior Notes due 2016 300 (300) ‐7.250% Senior Notes due 2019 300 ‐‐ 300New Senior Notes ‐ 775 775Total Debt $600 $1,0756% Convertible Preferred $115 ‐‐ $115Proved Reserves (MMBoe) 113.5 12.0 125.5% Oil 22% 90% 28%% Liquids 40% 96% 45%% Developed 41% 37% 41%Q4 2012 Production (MBoe/d) 15.4 2.7 18.2Proved R/P (Years) 20.1x 12.2x 18.9xPD R/P (Years) 8.3x 4.4x 7.8xPT Proved PV‐10% $692 $241 $933$475
  7. 7. Note: Some EFS operators off map.(1) Based on latest company presentations, as well as industry publications.  Some industry publication information may be out of date.VictoriaGoliadBeeLive OakMcMullenWilsonAtascosaBexarSan AntonioPVAMHRHuntBHPCHKCOGCOPCRKCRZOEOGFSTMROMURNFXPXDPXPSFYSTOTLMEFS OperatorsTexasEagle Ford Shale OperatorsEastern Volatile Oil Windows(1)Volatile OilCondensateRich GasGonzalesLavacaDeWitt6
  8. 8. 7Expanded Eagle Ford Acreage Position7267626054 54 5340 393528 2824229 70102030405060708090BHP 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. 341138118(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
  9. 9. • 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• 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 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 $844MM ($551MM of PD value)• 117 (82.0 net) wells producing• Objective is to lower PVA well costs by at least 10‐15% in 2013• 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• Includes over 300 infill locations• Rigs, infrastructure in place• Dedicated rigs and frac crew• Gas gathering and processing in place• Receiving premium LLS base pricing(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.Premier Shale Oil & Liquids PlaySizeable Position in a Successful Portion of the Eastern Oil Window of the Eagle Ford ShalePVA’s Pro Forma Eagle Ford Shale PositionGonzalesLavacaDeWittPVA Pro FormaBHP BillitonConocoPhillipsEOGForestNearby OperatorsMarathonPioneerPlainsStatoil8
  10. 10. 9Prospect AreaGross Acres Net AcresAverage RoyaltyPeach 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%Prospect AreaProducing WellsGross Non‐Producing LocationsNet Non‐Producing LocationsPeach Creek (MHR) 27 149 73.1Peach Creek (Hunt JV) 15 121 60.5Shiner (GeoSouthern JV) 3 72 32.6Shiner 1 3 3.0Total 46 345 169.3Total of 345 (169 net) locations across 40,565 (19,037 net) acres in Gonzales and Lavaca CountiesAcquired Asset in Detail
  11. 11. Significant Eagle Ford Shale Acreage and Drilling InventoryAreaProducing WellsRemaining LocationsTotal WellLocationsGross AcreageNet Acreage(1)Acres / Location(2)PVA Gonzales 54 190 244 26,239 21,261 108PVA Lavaca 17 105 122 16,191 13,759 133MHR Acquired 46 345 391 40,565 19,037 104Pro 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.(2) Represents gross acres per location.Combined Position Post Acquisition• 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 locations10
  12. 12. Both PVA’s legacy assets and the acquired position have strong and repeatable resultsStrong and Consistent Initial Production RatesPVA Legacy Assets Acquired MHR Assets• Average Gonzales IP / 30‐Day Rate of 921 / 621 BOEPD   • Average Lavaca IP / 30‐Day Rate of 939 / 644 BOEPD• Gonzales Averages of 15 Stages and 3,713’ Lateral Length (LL)• Lavaca Averages of 19 Stages and 4,583’ LL• Average Gonzales IP / 30‐Day Rate of 1,065 / 678 BOEPD• Average Lavaca IP / 30‐Day Rate of 1,503 / 849 BOEPD• Gonzales Averages of 16 Stages and 4,605’ LL• Lavaca Averages of 22 Stages and 6,114’ LL30‐Day Avg (BOEPD) IP (BOEPD) 30‐Day Avg (BOEPD) IP (BOEPD)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.Gonzales Lavaca Gonzales Lavaca11
  13. 13. 12LAVACA COUNTYPretax Rate of Return Sensitivities010203040506070809010040 50 60 70 80 90 100 110 120WTI Oil Price (Flat) - $/BblRateofReturnBFIT-%Base Case EUR = 590MBOE (8/8ths)Capex = $10.1MM (8/8ths) LLS PricingBase Case EUR = 590MBOE (8/8ths)Capex = $10.1MM (8/8ths) WTI PricingSensitivity Case EUR = 590MBOE (8/8ths)Capex = $9.1MM (8/8ths) LLS PricingSensitivity Case EUR = 590MBOE (8/8ths)Capex = $9.1MM (8/8ths) WTI Pricing$4.00/MMBtu Flat Gas PriceGONZALES COUNTYPretax Rate of Return Sensitivities010203040506070809010040 50 60 70 80 90 100 110 120WTI Oil Price (Flat) - $/BblRateofReturnBFIT-%Base Case EUR = 460MBOE (8/8ths)Capex = $9.1MM (8/8ths) LLS PricingBase Case EUR = 460MBOE (8/8ths)Capex = $9.1MM (8/8ths) WTI PricingSensitivity Case EUR = 460MBOE (8/8ths)Capex = $8.1MM (8/8ths) LLS PricingSensitivity Case EUR = 460MBOE (8/8ths)Capex = $8.1MM (8/8ths) WTI Pricing$4.00/MMBtu Flat Gas PriceGonzales County(1) Lavaca County(1)• Assumptions• Longer lateral lengths in 2013 vs. PUD assumption• 590 MBOE EUR type curve• Drilling and completion (D&C) costs per below• Assumptions• Longer lateral lengths in 2013 vs. PUD assumption• 460 MBOE EUR type curve• Drilling and completion (D&C) costs per belowAttractive Economics in Volatile Oil WindowCompelling Economics & Value at Varying Oil PricesKey TakeawaysD&C of$9.1MMD&C of$8.1MMIRR 40 – 52% 52 – 76%BTAX PV‐10(2) ($MM) $5.6 – 7.4 $6.6 – 8.4Breakeven(3) ($/BOE) $47 – 57 $41 – 52(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.(3) Before tax PV‐10 breakeven WTI oil price.Key TakeawaysD&C of$10.1MMD&C of$9.1MMIRR 37 – 52% 50 – 71%BTAX PV‐10(2) ($MM) $6.1 – 8.2 $7.1 – 9.2Breakeven(3) ($/BOE) $47 – 57 $42 – 52
  14. 14. 132013 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 areasPro Forma Capital Expenditures by Area(1) Pro Forma Capital Expenditures by Type(1)Other4%Eagle Ford D&C87%Other D&C4%Land5%Revised 2013 Capital Plan(1) Change in mid‐points of full‐year 2013 guidance, adjusted for acquired Eagle Ford assets.Other3%Pearsall2%Existing Eagle Ford64%Acquired Eagle Ford Assets28%Mid‐Continent3%
  15. 15.$0$5$102011 2012 PF 2013E88% 86% 86% 8% 7% 6% 7% 14• 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 WTIPositive Production TrendPre Acquisition Eagle Ford Production (MBOEPD)Acquisition’s Effect on Production Volumes and MixOil and Condensate NGLs Natural GasPost Acquisition Eagle Ford Production (MBOEPD)$0$5$102011 2012 2013E88% 84% 85% 9% 8% 7% 8% 
  16. 16. 15Appalachian RegionEagle Ford and Other RegionsMid‐ContinentProved reserves: 12.5 MMBOE% Oil/NGLs: 47%% PD: 79%2012 Production: 1,211 MBOEPro Forma Eagle FordProved reserves: 38.2 MMBOE% Oil/NGLs: 92%% PD: 37%2012 Production: 3,092 MBOE Pro Forma Penn VirginiaProved reserves: 125.5 MMBOE% Oil/NGLs: 46%% PD: 41%2012 Production: 6,529 MBOE(1)HaynesvilleProved reserves: 17.2 MMBOE% Gas: 86%% PD: 26%2012 Production: 454 MBOE Selma ChalkProved reserves: 17.6 MMBOE% Gas: 99%% PD: 54%2012 Production: 847 MBOECotton ValleyProved reserves: 39.6 MMBOE% Oil/NGLs: 34%% PD: 34% 2012 Production: 882 MBOE Current Geographic FootprintEmerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas PlaysTotal CompanyNote: 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. (1) Excludes divested production.MarcellusProved reserves: 0.5 MMBOE% Gas: 100%% PD: 23%2012 Production: 43 MBOE 
  17. 17. 16Note: Latest through April 3, 2013; excludes two Marcellus locations.(1)  Median gross EUR for all PUD 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” locationsPro Forma PVA Has a Healthy Inventory of Drilling LocationsPlayGross Undrilled LocationsAverage Working InterestGross EUR (MBOE/Well)(1)Existing Eagle Ford (Gonzales) 190 83% 394Existing Eagle Ford (Lavaca) 105 88% 513Acquired MHR Assets 345 48% 385Granite Wash 52 18% 809Cotton Valley 78 71% 903Haynesville 78 77% 869Cotton Valley (vertical) 181 71% 172Selma Chalk 104 96% 302Totals 1,133Pro Forma Total Company Drilling Inventory
  18. 18. Regional / Play Production BreakoutExpanding Production Volumes from Eagle Ford AssetsProduction Volumes by Operating Region (MMBOE)• Eagle Ford production growth is PVA’s focus going forward• Production volumes in the Eagle Ford are expanding from pro forma 40% in 2012 to at least 60% in 201317Note:  2013 annual production guidance of 6,518 MBOE – 7,175 MBOE, midpoint of 6,847 MBOE.(1) Excludes divested production.21% 15% 11% 35% 21%14%18% 15%10%12%8% 5% 14%40% 42%18% 2011 2012 2013ECotton Valley Mid‐Continent Selma ChalkMarcellus Haynesville PVA Legacy Eagle FordAcquired MHR Eagle Ford6.25.86.8(1)(1)(1)(1)
  19. 19. 18Production Mix Over TimeIncreasing Liquids Production• Since 2011, PVA has consistently grown its annual liquids production• The Acquisition will significantly increase liquids production and overall production growth• In 2013, 92% of PVA’s capex program will be allocated to the Eagle Ford • Expected to run six rigs in 2013, post acquisition• Shift in liquids focused production has resulted in 2012 pro forma production being 53% liquids• 40% oil and 13% NGLs17%35%40%12%14%13%12%72%52%47%33%55%2011 2012 2012 PF 2013EOil & Condensate NGLs Natural GasNote:  2013 annual crude oil and NGLs production mix guidance of 64.5% ‐ 69.4%.
  20. 20. 19Oil Based Strategy Continues• PVA has significantly increased its liquids percentage of revenue since the beginning of 2011Annual Product Revenue by Commodity (Before Hedges) Annual EBITDAXNote: 2013E based on the mid‐point of updated guidance and price deck for 2013: ($90.96 / $3.51).$220$248$322$0$100$200$3002011 2012 2013E89% Liquids$300$310$425$0$200$4002011 2012 2013EOil NGL Gas40%14%46%74%16%10%
  21. 21. 20$1.98$2.18$1.95$5.28$5.11$4.58$6.12$38.70$47.67$52.62$62.02$45.25$38.96$33.95$24.96$4.85$5.13$4.80$4.74$1.55$4.25$2.00$1.63$1.74$0$10$20$30$40$50$60$702011 2012 2012 PF 2013ECash Margin LOEG&P and transportation Production taxesCash G&A (excludes share‐based compensation)Unhedged Cash Margin Over Time ($/BOE)Note: Cash margin ($ / BOE) is defined as total product revenues, excluding the impact of hedges, less direct operating expenses per unit of equivalent production.Assumed price deck for 2013: ($90.96 / $3.51). Realized PriceCash MarginOperating Margins• PVA has consistently increased cash margin since 2011 through:• Investment in higher rate‐of‐return oil projects• Advantaged LLS pricing• Decreasing per unit operating costs• The Acquisition is expected to further expand cash margins 
  22. 22. 21Quarterly Adjusted EBITDAX and EBITDAX Margin ($ / BOE)$48.41$45.88$43.72$40.61$39.10$36.48$26.37$25.01 $24.54$22.95$19.79$13.56PVA PFGDP PVA CWEI CRZO FST PDCE BBG CRK Antero XCO KWKComparative Q4 2012 EBITDAX Margins ($ / BOE)(2)• 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)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.(3) Pro forma for the Acquisition.Strong Margins vs. Peers$49$33$46 $45 $44$48$66$62$64$61$60$62$20.73$20.76$21.72$24.38$33.01$34.77$35.44$34.51$28.50$18.91$43.72$39.73$0$701Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12(3)
  23. 23. • 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$3.76  $3.75  $3.75  $3.82 $4.02 $4.03  $4.03 $4.16  $4.07  $4.07 $4.24  $4.27 $4.03 $0$1$2$3$4$5$60510152025301Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14MMBtu per Day (000s)Weighted Avg. Floors and Swaps  ($/MMBtu)Weighted Average Floor /Swap Price by QuarterWeighted Average Ceiling /Swap Price by Quarter$98$97$96 $96$95$94 $94$102$101$99 $99$95$75$80$85$90$95$100$105$11001,0002,0003,0004,0005,0006,0007,0001Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14Barrels per DayWeighted Avg. Floors and Swaps  ($/Bbl)Weighted Average Floor /Swap Price by QuarterWeighted Average Ceiling /Swap Price by Quarter22Crude Oil Hedges (Swaps and Collars)(1)(1) As of 3/25/13.Hedging StrategyProtect Cash FlowNatural Gas Hedges (Swaps and Collars)(1)
  24. 24. Investment Highlights23• Transformational acquisition increases footprint in the volatile oil window core of the Eagle Ford • With 82,995 gross (54,057 net) of highly contiguous acres, our pro forma position will be significant with attractive leverage on a per share basis• MHR’s acreage is adjacent to our current position with similar geologic and reserve characteristics to our current Eagle Ford assets• Enhances production growth, with 2013E production (7.5 months) of approximately 5,500 BOEPD, representing a 34% increase (23% increase in BOEPD on a full‐year basis)• Increases drilling inventory in the Eagle Ford Shale to 640 (420 net) locations• Attractive drilling economics with PV‐10 breakeven WTI prices of $47 ‐ $57 per barrel • 11% increase in proved reserves by adding 12.0 MMBOE (96% liquids / 37% PD), increases Eagle Ford Shale proved reserve base by 46%MROMHRPVAHUNTEOGEOGPVAGonzalesLavacaDeWittACREAGEMHR LEGACYPVA LEGACYOPERATOREOGMAGNUM HUNTERPVAHUNTMARATHON
  25. 25. 24Appendix
  26. 26. Transformational Acquisition in the Eagle Ford Shale• Penn Virginia is acquiring Eagle Ford Shale assets from Magnum Hunter for approximately $400MM• Assets are adjacent to PVA’s current Eagle Ford position in Gonzales and Lavaca Counties • 40,565 (19,037 net) acres in Gonzales and Lavaca counties• 46 (22.1 net) producing wells and drilling inventory of 345 (169 net) locations(1)• Approximately 3,173 BOEPD – February 2013• Approximately 5,500 BOEPD – 2013E (final eight months)• 12.0 MMBOE of proved reserves (37% PD / 96% Liquids)(2)Attractive Transaction Valuation• Transaction Value / Production ($ / BOEPD – February 2013) = ~$126,000• Transaction Value / Production ($ / BOEPD – 2013E) = ~$73,000• Transaction Value / Proved Reserves ($ / BOE) = ~$33.00• Transaction Value / 2013E EBITDAX ($93MM over 7.5 months, annualized) = ~2.7xAcquisition and  Tender Offer Financing• We have priced $775MM of 8.50% senior unsecured notes due 2020 in a private placement• Up to $330MM for tender offer for $300MM of 10.375% senior notes due 2016 @ 106%• At least $400MM to fund the MHR acquisition• Up to $40MM common equity option to issue up to 10MM shares to MHR @ $4/shareClosing Timeline• April 2nd – PSA signed• April 2nd – Acquisition announced• April 3rd – Commence private placement• April 10th – Price upsized notes private placement• By mid‐May 2013 – Close acquisitionTransaction Overview(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.25
  27. 27. Acquired MHREagle Ford12%Selma Chalk13%Haynesville7%PVA LegacyEagle Ford36%Cotton Valley13%Mid‐Continent18%Marcellus1%PVA LegacyEagle Ford65%Acquired MHREagle Ford26%Cotton Valley1%Selma Chalk2%Mid‐Continent11%Acquired MHREagle Ford10%Selma Chalk14%Haynesville14%Mid‐Continent10%Marcellus0% PVA LegacyEagle Ford21%Cotton Valley32%Acquired MHREagle Ford9%Selma Chalk18%Haynesville9%Marcellus0% PVA LegacyEagle Ford19%Cotton Valley26%Mid‐Continent19%262012 Production (17.8 MBOEPD)Pre‐Tax PV‐10 ($933.2MM)(1)Proved Developed Reserves (51.4 MMBOE)Proved Reserves (125.5 MMBOE)Pro Forma Reserves, PV‐10 and Production by Region / Play(1)  Based on SEC pricing.  
  28. 28. 27Revised for Proposed MHR Acquisition Assuming 5/15/13 Closing DateFull‐Year 2013 Guidance TableProduction: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 Pro Forma2013 GuidanceCurrent Full‐Year2013 GuidanceAdjustments for MHRAcquisition / One Less Rig(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. (c)  Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities . 
  29. 29. 79%76%73% 72%68%61%49% 47%38%9%5%1%86%87%0000011111CWEI Aurora PVAPFCRZO PVA SFY GDP PDCE CRK FST BBG XCO KWK Antero4Q 2012 Oil Production Mix284Q 2012 Unhedged Oil Revenue (% of Revenue)Production and Revenue MetricsSource: Public filings and investors presentations. Penn Virginia pro forma for the Acquisition.4Q 2012 Cash Margin (Unhedged)4Q 2012 Average Realized Price (Unhedged)$66.94$59.14$53.49$50.85$45.19$43.41$36.06 $36.05$32.65$30.03$22.23 $21.91 $20.78$72.37020406080Aurora CWEI PVAPFPVA SFY CRZO GDP PDCE BBG FST CRK Antero KWK XCO65%47%39%36% 35%30%27%18%17% 16%2% 1% 0%68%00000111CWEI Aurora PVAPFPVA SFY CRZO GDP PDCE BBG FST CRK XCO KWK Antero16.39$72.37$66.94$59.14$53.49$50.86$45.19$43.41$36.06 $36.05$32.65$30.03$22.23 $21.91 $20.788.378.265.8234.5039.30$ 0$ 10$ 20$ 30$ 40$ 50$ 60$ 70$ 80Aurora CWEI PVAPFPVA SFY CRZO GDP PDCE BBG FST CRK Antero KWK XCOCash M arginCash G&ATotal Production Expenses
  30. 30. 1‐Year F&D Costs, Drill‐bit ($ / BOE)(1)293‐Year F&D Costs, Drill‐bit ($ / BOE)(2)542%428%374%281%194%161%140%101%54%37%0%150%300%450%600%Antero PDCE CRZO CWEI SFY PVA FST BBG CRK GDP XCO KWK2243% 1226%2012 Reserve Replacement, Total(3)Operational and Reserve Metrics$25.96$19.37 $19.30 $18.63$14.92$13.85$11.36 $11.34 $10.91 $10.71$5.21$1.73$0$5$10$15$20$25CRZO GDP BBG PVA CWEI FST CRK SFY XCO KWK PDCE AnteroNote:  CRZO metrics represent U.S. assets only.(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.(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 period from 2010 to 2012. (3) Reserve replacement calculated by taking the sum of purchases, extensions, discoveries and improved recovery of proved reserves by annual production.(4) Pro forma for all recently announced transactions, including with respect to PVA, the Acquisition.2012 Proved Reserves (MMBOE)(4)192.1183.4 181.8 178.7 174.0125.5118.0 115.191.875.455.5020406080100120140160180200Antero SFY KWK FST PDCE BBG PVA PF XCO CRZO CRK CWEI GDP821.7 $43.34 $43.25$34.14$26.37 $25.47$23.13$19.53$17.65 $17.08$15.30$3.74 $2.61$0$10$20$30$40KWK GDP CRZO XCO BBG CRK PVA CWEI FST SFY PDCE Antero
  31. 31. 30Non‐GAAP Reconciliation2008 2009 2010 2011 2012Adjusted EBITDAXNet income (loss) from continuing operations $       93.6   $  (130.9) $    (65.3) $  (132.9) $  (104.6)Add: Income tax expense (benefit)          55.6         (85.9) (42.9)      (88.2)      (68.7)     Add: Interest expense          24.6           44.2  53.7       56.2       59.3      Add: Depreciation, depletion and amortization        135.7  154.4      134.7     162.5     206.3    Add: Exploration          42.4  57.8        49.6       78.9       34.1      Add: Share‐based compensation expense            6.0  9.1          7.8         7.4         6.3        Add/Less: Derivatives (income) expense included in net income         (29.7) (31.6)       (41.9)      (15.7)      (36.2)     Add/Less: Cash receipts (payments) to settle derivatives           (7.6)          58.1          32.8          27.4          29.7 Add/Less: Loss on firm transportation commitment               ‐                 ‐                ‐                ‐           17.3 Add: Impairments          20.0  106.4      46.0       104.7     104.5    Add/Less: Net loss (gain) on sale of assets, other          (33.2)          (2.0)          (1.2)          22.0           (0.6)Adjusted EBITDAX  $     307.4   $    179.7   $    173.3   $    222.5   $    247.6 dollars in millionsYear ended December 31,
  32. 32. Penn Virginia Corporation4 Radnor Corporate Center, Suite 200Radnor, PA 19087610‐687‐8900www.pennvirginia.com