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    PVA Investor Presentation PVA Investor Presentation Presentation Transcript

    • Investor PresentationMarch 21, 2012NYSE: PVA
    • 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: the volatility of commodity prices for natural gas, NGLs and oil; our ability to develop, explore for and replace oil and gas reserves andsustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write‐downs or write‐offs of our reserves or assets; the projected demand for and supply of natural gas, NGLs and oil; reductions in the borrowing base under our revolvingcredit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oiland 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 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 governmental regulationor enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economicand political conditions; and other risks set forth in our filings with the U.S. 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, including our Annual Report onForm 10‐K for the year ended December 31, 2011. Readers should not place undue reliance on forward‐looking statements, which reflect management’s views only asof the date hereof. We undertake no obligation to revise or update any forward‐looking statements, or to make any other forward‐looking statements, whether as aresult 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, 2011, 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 estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be economicallyproducible in future years from known oil and gas reservoirs under existing economic and operating conditions and government regulation prior to the expiration of thecontracts providing the right to operate, unless renewal of such contracts is reasonably certain. Probable reserves are those additional reserves that are less certain tobe recovered than proved reserves, but which are more likely than not to be recoverable (there should be at least a 50% probability that the quantities actuallyrecovered will equal or exceed the proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable thanprobable reserves (there should be at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possiblereserve estimates). “3P” reserves refer to the sum of proved, probable and possible reserves. Estimated ultimate recovery (EUR) is the sum of reserves remaining as ofa given date and cumulative production as of that date. 2
    • PVA Overview• Small‐cap domestic onshore E&P company  • Very active in the Eagle Ford Shale oil play with excellent results to date: YE11 PV‐10 of $278 MM • HBP positions in Granite Wash, East Texas, Mississippi and Appalachia: YE11 PV‐10 of $596 MM• PVA is executing a strategy of growth in oil and NGL rich plays • 2010 and 2011 have been transformational years, diversifying our portfolio towards oil / NGLs • Successful drilling results in the Eagle Ford Shale – 40 wells on‐line as of 3/20/12 • Adding to Eagle Ford drilling inventory – recent AMI in Lavaca County • Growth in EBITDAX has resulted• Attractively valued • Trades at 1.4x 2012E CFPS vs. 4.0x for peers (64% discount) • Trades at 4.0x 2012E EBITDAX vs. 5.9x for peers (32% discount) • Only $60 MM ($1.32 / share) of implied market value for non‐proved reserves and acreage • 4.2% dividend yield and substantial upside to increased natural gas prices 3
    • Options to Build Financial Liquidity• Current liquidity is sufficient and we will build it up as 2012 progresses • 2012 CAPEX fully‐funded and largely discretionary; no material debt maturities until 2016; pending  borrowing base expected to be similar to current commitment amount of $300 MM • Immediate liquidity of approximately $184 MM at 2/29/12 and 2012E cash flow outspend of $107‐ 157 MM• Significant asset sale likely during 2012 • Reduces bank debt and replenishes liquidity going into 2013 • Precludes any need for capital markets, which are currently unattractive, or reduced spending • Sale candidates include high‐decline, liquids‐rich assets or low‐decline, gassy assets• Significantly reduced capital expenditures • 2012 capital program of $300‐325 MM is ~30% less than $446 MM in 2011 • 85% Eagle Ford (oily) and 8% Granite Wash (NGLs/oil) ‐ no natural gas drilling due to weak prices• Continue active hedging program • Oil: 66% hedged for 2012 at weighted average of $100.04 per barrel (floor/swap) • Gas: 31% hedged for 2012 at weighted average of $5.43 per MMBtu (floor/swap) • 2013: 1,872 BOPD hedged at weighted average of $95.73 per barrel (floor/swap); no gas hedges • 2014: 1,750 BOPD hedged at weighted average of $100.19 per barrel (floor/swap); no gas hedges • Hedges help support borrowing base and strong cash flow margins 4
    • PVA’s Growth Strategy is Sound Gas‐to‐Oil / Liquids Has Increased Revenues and Cash Flows• We commenced our “Gas‐to‐Oil” transition in mid‐2010 • Built Eagle Ford position from initial 6,800 net acres to at least 23,000 net acres in just over one year – Up to approximately 190 well locations (41 drilled with up to 150 drilling locations remaining) – Includes acreage and locations to be potentially earned in recently announced AMI in Lavaca County • Grew oil/NGL production from 2,461 Bbls/day in 2Q10 to 7,194 Bbls/day in 4Q11 (+192%) – Up 43% from 5,033 Bbls/day in 4Q10 • Other oily / liquids‐rich plays include the Cotton Valley and Granite Wash• Retain substantial core gas assets for eventual gas price recovery • East Texas Haynesville Shale, Mississippi Selma Chalk and Appalachia• Make selective divestitures to increase margins, operational focus, liquidity• Continue to expand oil and liquids reserves and drilling inventory • Will test a horizontal oil prospect in the Mid‐Continent in 2012• Continue to grow oil and liquids production and cash flows 5
    • Value Has Shifted to Oil/Liquids Value Growth From 2009‐2012 Due to Drive Towards Oil & NGLs • In mid‐2010, PVA implemented a strategy to transition from dry gas to oil & liquids • Since then, the decrease in gas prices and increase in oil & liquids prices has shifted the  market from a “6:1” to a “20:1” liquids‐to‐gas price environment • Examining revenue growth by commodity type reveals PVA’s true growth in value Perception: “6‐to‐1” Equivalent Environment Reality: “20‐to‐1” Price Environment Gas Producer With Little to No Production Growth Oil/NGL Producer With Revenue Growth Pro Forma Production by Commodity Pro Forma Quarterly Revenue by Commodity MMcfe per day (1 Bbl = 6 Mcfe) Pre‐Hedging; $MM 160 $80 120 $60 ~70% ~43% 80 $40 40 $20 ~57% ~30% 0 $0 Base Gas Shale Gas Oil NGLs Gas Oil NGLs 6Note: Pro forma to exclude South Texas and South Louisiana assets sold in January 2010 and primarily Arkoma Basin assets sold in August 2011
    • EBITDAX and Cash Margin Growth Shift to Oil/Liquids Strategy Has Dramatically Improved Cash Flow Margins • EBITDAX has increased significantly since mid‐2010 when we began our strategic shift  towards oil and NGL growth • Gross operating margin per Mcfe has also improved significantly due to the increase in  oil prices and declining operating costs per unit Quarterly EBITDAX and Cash Margins $70 $7 $60 $6 $50 $5 $ per Mcfe $ Millions $40 $4 $30 $3 $20 $2 $10 $1 $0 $0 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 Adjusted EBITDAX ($MM) Gross Operating Margin per Mcfe 7Note: Gross operating margin per Mcfe is defined as total product revenues, excluding the impact of hedges, less direct operating expenses per unit of equivalent production
    • PVA Appears Undervalued Valuation Multiples Below Peers Who are Also Leveraged, Have Less Oil & Liquids and No Dividend • Trades at 1.4x analysts’ mean 2012E CFPS1 – Trades at a 64% discount to selected peers which trade at an average of 4.0x • Trades at 4.0x analysts’ mean 2012E EBITDAX1 – Trades at a 32% discount to selected peers which trade at an average of 5.9x • $935MM enterprise value is only $60MM ($1.32/share) above YE11 PV‐10 of $874MM2 • YE11 PV‐10 of Eagle Ford 3P reserves alone is $360MM, using a $9 MM drilling and  completion well cost and allocating no value to Lavaca County at this time3 2012E CFPS and EBITDAX Multiples 8.0x 6.0x 4.0x 2.0x 0.0x PVA Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Price‐to‐2012E CFPS TEV‐to‐2012E EBITDAX1 – Sources: First Call; peers: CRK, FST, GDP, PETD and PQ; as of 3/19/12 82 – PV‐10 pretax value of $874MM based on SEC pricing of $96.19 per Bbl for oil and $4.12 per MMBtu for natural gas3 – Derived from our 2011 reserve report prepared by our independent petroleum engineers
    • What is Our Response? Continued Momentum Towards Oil and NGL, Higher Revenues and Margins Continue to increase oil and liquids exposure • 37% of 4Q11 production vs. 18% in FY10; ~50% by 4Q12 • 42% of 2012E production and 78% of 2012E product revenues • Eagle Ford‐driven with long‐term goal to add more of this play and other oily inventory Retain long‐term optionality of core gas assets • East Texas, Mississippi, Granite Wash and Appalachia – largely HBP Improve liquidity and financial position • Fully‐funded 2012 CAPEX plan, looking to make a near‐term asset sale to boost liquidity Communicate story: stress attractive valuation, leverage to oil  and liquids, and retained exposure to gas price recovery • Undervalued on most metrics, despite solid operations and cash flow growth • Change perception of PVA as a gas‐weighted producer to that of an oil & liquids producer • Common dividend yield currently about 4.2% – attractive relative to other small E&P firms  who typically pay zero dividends 9
    • Core Operating Regions Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays 2012E CAPEX: $300MM ‐ $325MM ~85% Eagle Ford / ~30% Less than 2011 2012E Production: 40.0‐43.0 Bcfe ~42% Oil & Liquids; ~50% in 4Q12E 2012E Production: 41.5 Bcfe 2011 Proved Reserves: 883 Bcfe Oil / Liquids Wet Gas  Dry Gas 10Note: Based on 2/22/12 operational update; see Appendix
    • Eagle Ford Shale The Most Economic Eagle Ford Shale Wells are in the Volatile Oil & Condensate Rich Gas Windows Premier Shale Oil & Liquids Play Volatile Oil • 31,400 (≥23,100 net) acres in Gonzales and  Lavaca Counties, TX1 Condensate Gonzales Rich Gas – Operator in Gonzales with 83% WI – Operator in Lavaca with at least a 57%WI1 San Antonio – Avg. IP/30‐day rates of 1,025/675 BOEPD Wilson Lavaca – Type curve EUR of ~400 MBOE2 Bexar – 89% oil, 5% NGLs and 5% gas, post processing – 4Q11 D&C costs: estimated $8.0MM per well Atascosa – Reduced proppant costs and stage sizes Karnes DeWitt – Avg. spud‐to‐TD / spud‐to‐sales: 22/54 days – Initial positive down‐spacing test of 3‐well pad Victoria • Up to 150 remaining drilling locations1 Goliad – 40 wells producing ~9,500 BOEPD (~5,900  BOEPD, net), 3 wells drilling and 1 well WOC – Excludes any potential Austin Chalk or deeper  Texas potential McMullen Live Oak Bee • Rigs, infrastructure in place Acreage Valuations  – Dedicated rigs and fracturing crew Have Increased  – Net oil price at ~$9/barrel premium to WTI Significantly in Recent  – Gas gathering and processing in place EFS Transactions1 – Includes approximately 13,500 (8,025 net) acres and up to 40 potential locations to be earned in the recently announced AMI in Lavaca Co. 112 – Internally generated type curve based on production history of wells drilled to date by PVA
    • Eagle Ford Shale Premier Acreage Position in Volatile Oil Window; Lavaca AMI Provides Additional Upside PVA’s Eagle Ford Acreage  Volatile Oil Window and Potential is Well‐ Gonzales Notable PVA & Industry Results Positioned Based on  County PVA Well Name IP Rates Overall Excellent  MHR Gardner 1H 1,247 BOEPD Hawn Holt 9H 1,877 BOEPD Industry Results in Area Hawn Holt 10H 1,188 BOEPD Hawn Holt 11H 1,190 BOEPD Hawn Holt 12H 1,495 BOEPD Hawn Holt 13H 1,399 BOEPD Hawn Holt 15H 1,298 BOEPD Munson Ranch 1H 1,921 BOEPD Munson Ranch 3H 1,538 BOEPD Munson Ranch 4H 1,416 BOEPD Lavaca Munson Ranch 6H Rock Creek Ranch 1H 1,808 BOEPD 1,257 BOEPD County Schaefer 3H 1,129 BOEPD Munson Ranch 5H 1,164 BOEPD D. Foreman 1H 1,202 BOEPD EOG Other Operators IP Rates MHR – Oryx Hunter 1H 2,044 BOEPD MHR – Kudu Hunter 1H 1,590 BOEPD MHR – Southern Hunter 1H 1,321 BOEPD PVA Acreage MHR – Furrh 2H MHR – Snipe Hunter 1H 1,275 BOEPD 2,033 BOEPD PVA AMI with “Major”1 MHR – Leopard Hunter 1H 1,333 BOEPD EOG – King Fehner Unit 1.4 – 1.7 MBOEPD 3‐D Seismic Survey EOG – Kerner Carson Unit 1.8 – 2.6 MBOEPD EOG – Hill Unit 1.6 – 2.0 MBOEPD Notable PVA Results EOG – Meyer Unit 1.9 – 3.4 MBOEPD EOG – Mitchell Unit 3.3 – 3.6 MBOEPD Notable Industry Results EOG – Central Gonzales avg. 1,465 BOEPD1 – Includes approximately 13,500 (8,025 net) acres and up to 40 locations to be earned in the recently announced AMI in Lavaca Co. 12Note: Industry results based on peers’ investor presentations  and reported IP wellhead rates (pre‐processing);  production “windows” are PVA’s approximation
    • Eagle Ford Shale Positive Trends: Volumes Up, Costs Down • During 2011 and into early 2012, we have quickly ramped up the Eagle Ford Shale • We also reduced our average well cost during the second half of 2011 which, combined  with strong oil prices, has contributed to increased rates of return and margins • The cost decline is due primarily to drilling efficiencies and altered completion design 2011‐2012 Sales Volumes by Commodity 2H11 Drilling & Completion Costs 600 $12 500 $10 400 $8 $ Millions MBOE 300 $6 200 $4 11 Wells 13 Wells 100 $2 0 $0 1Q11 2Q11 3Q11 4Q11 Jan‐Feb 2012 3Q11 4Q11 x 1.52 * Net Oil Sales Net NGL Sales Net Gas Sales Average Total Well Cost Average Completion Cost 13* January & February 2012 production multiplied by 91/60, or 1.52x
    • Eagle Ford Shale Gonzales Type Curve Supported by Actual Wells Results • Current type curve EUR of ~400 MBOE; previously ~280 MBOE • Assuming $8.0 MM well costs, the pre‐tax rate of return for our average Eagle Ford well  is approximately 50% at $100 flat oil, with $6MM of NPV (BTAX) • Typical completion consists of 15‐16 stages over 4,000’ lateral • Efforts will continue to drive down drilling and completion costs Eagle Ford Shale ‐ Gonzales Type Curve 800 700   Current Type Curve (~400 MBOE) 600   Old (Exponential) Type Curve (~280 MBOE) 500BOEPD 400 300 200 100 0 0 6 12 18 24 30 36 Production Month 14Note: Internally generated type curve based on production history of wells drilled to date by PVA
    • Why PVA? Investment Highlights• Diversified and valuable portfolio of high‐quality assets• Track record of low‐cost, high‐return operations• Drilling and acquisitions focused on high return play types• Successful transition from dry gas to oil and liquids• Ample supply of economic drilling locations• Retained optionality of natural gas assets• Compelling value proposition 15
    • Appendix
    • Mid‐Continent: Liquids‐Rich Play Types High‐Margin, Liquid‐Rich Reserves and Production • Positioning Anadarko Basin – CHK development drilling JV • ~10,000 net acres in Washita Co. • operate about one‐third; ~28% WI – ~40,000 net acres in other exploratory plays • Viola Lime test by mid‐year 2012 (oily) • Reserve Characteristics / Geology – Granite Wash: 48% liquids; attractive IRRs – Historical EURs > 5.0 Bcfe; assuming 4.0 Bcfe  for remaining wells – $1.66 PV‐10 breakeven gas price ($90 per  barrel oil price) • 2012 Activity – Up to 7 (2.3 net) Granite Wash wells and        1 (0.5 net) Viola Lime test well – Granite Wash non‐operated drilling – Up to $20‐25MM of CAPEX (~8% of total) 17Note: Based on 2/22/12 operational update
    • Crude Oil Hedges Protecting our Capital Budget and Well Economics• We have recently expanded our crude oil hedges given our increased oil drilling activity• Our oil hedges thus far are equal to or greater than our forecasted oil price for 2012‐2013 Crude Oil Hedges1 Swaps and Collars 4,500 $110 Weighted Average Floor / Weighted Avg. Floors and Swaps  ($/Bbl.) Swap Price by Quarter 4,000 $105 $101 $101 $100 $100 $100 $100 $100 3,500 $99 $100 $97 $97 3,000 $93 $93 $95 Barrels per Day Forecast Price by Quarter 2,500 $90 2,000 $85 1,500 $80 1,000 $75 500 $70 0 $65 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 181 – As of 3/16/12
    • Natural Gas Hedges Protecting our Cash Flows During Depressed Gas Price Environment• Our 2012 natural gas hedges have locked in prices well above the forecast• Nevertheless, we are not drilling dry gas plays as the commodity remain oversupplied Natural Gas Hedges1 Swaps and Collars 40 $6 Weighted Avg. Floors and Swaps  ($/MMBtu) Weighted Average Floor / $5.70  Swap Price by Quarter $5.31  $5.31  30 $5.10  $5 MMBtu per Day (000s) 20 $4 Forecast Price by Quarter $3.36  $3.03  10 $2.87  $3 $2.74  0 $2 1Q12 2Q12 3Q12 4Q12 191 – As of 3/16/12
    • 2012 Guidance Table As of February 22, 2012 4th Quarter Full Year Full‐YearDollars in millions, except unit data 2011 2011 2012 Guidance Production: Natural gas (Bcf)                   6.8                  33.4          23.5  ‐          24.4  Crude oil (MBbls)                 450               1,283       2,000  ‐       2,275  NGLs (MBbls)                  212                   907           750  ‐           825  Equivalent production (Bcfe)                10.7                  46.6          40.0  ‐          43.0  Equivalent daily production (MMcfe per day)             116.7               127.5       109.3  ‐       117.5  Equivalent production (MBOE)             1,789               7,759       6,667  ‐       7,167  Equivalent daily production (MBOE per day)                19.4                  21.3          18.2  ‐          19.6  Percent crude oil and NGLs 37.0% 28.2% 41.3% ‐  43.3% Production revenues: Natural gas $                23.4               137.1          66.5  ‐          69.1  Crude oil  $                44.3               119.6       189.0  ‐       215.0  NGLs  $                  9.6                  43.4          32.0  ‐          35.2  Total product revenues $                77.4               300.0       287.5  ‐       319.2  Total product revenues ($ per Mcfe) $                7.20                  6.45          7.19  ‐          7.42  Total product revenues ($ per BOE) $             43.23               38.67       43.12  ‐       44.54  Percent crude oil and NGLs 69.7% 54.3% 76.9% ‐  78.4% Operating expenses:   Lease operating ($ per Mcfe) $                0.70                  0.79          0.80  ‐          0.85    Lease operating ($ per BOE) $                4.17                  4.77          4.80  ‐          5.10    Gathering, processing and transportation costs ($ per Mcfe) $                0.36                  0.33          0.28  ‐          0.33    Gathering, processing and transportation costs ($ per BOE) $                2.18                  1.95          1.68  ‐          1.98    Production and ad valorem taxes (percent of oil and gas revenues) 3.1% 4.6% 4.0% ‐  4.5%   General and administrative: Recurring general and administrative $                  6.9                  38.5          39.0  ‐          41.0  Share‐based compensation $                  1.8                    7.4            6.5  ‐            7.0  Restructuring $                  0.7                    2.4  Total reported G&A $                  9.4                  48.3          45.5  ‐          48.0  Exploration expense $                10.7                  78.9          43.0  ‐          46.0    Unproved property amortization $                  8.5                  42.0          36.0  ‐          38.0  Depreciation, depletion and amortization ($ per Mcfe) $                4.59                  3.49          4.75  ‐          5.25  Depreciation, depletion and amortization ($ per BOE) $             27.56               20.95       28.50  ‐       31.50  Adjusted EBITDAX $                62.2               219.5       200.0  ‐       240.0  Net cash provided by operating activities $                41.6               144.7       175.0  ‐       205.0  Capital expenditures: Development drilling  $                99.9               307.8       240.0  ‐       245.0  Exploratory drilling $                10.9                  64.1          30.0  ‐          35.0  Pipeline, gathering, facilities $                  6.2                  12.5            5.0  ‐          10.0  Seismic $                  2.2                  11.2            5.0  ‐          10.0  Lease acquisitions, field projects and other $                  3.6                  50.0          20.0  ‐          25.0  20   Total oil and gas capital expenditures $             122.8               445.6       300.0  ‐       325.0 
    • Non‐GAAP Reconciliations Adjusted EBITDAX Year ended December 31, 2006 2007 2008 2009 2010 2011Adjusted EBITDAX dollars in millionsNet income (loss) from continuing operations $       44.2  $      26.5  $      93.6  $  (130.9) $    (65.3) $  (132.9)Add: Income tax expense (benefit)          50.0          30.5          55.6        (85.9)       (42.9)       (88.2)Add: Interest expense            6.0          20.1          24.6          44.2         53.7        56.2Add: Depreciation, depletion and amortization          56.7          88.0        135.7       154.4      134.7      162.5Add: Exploration          34.3          28.6          42.4         57.8        49.6        78.9Add: Share‐based compensation expense            1.1            1.6            6.0           9.1          7.8          7.4Add/Less: Derivatives (income) expense included in net income         (30.7)           2.0        (29.7)       (31.6)       (41.9)       (15.7)Add/Less: Cash receipts (payments) to settle derivatives          10.5          14.1          (7.6)         58.1          32.8          27.4 Add: Impairments            8.5            2.6          20.0       106.4        46.0      104.7Add/Less: Net loss (gain) on sale of assets, other                ‐          (12.6)        (33.2)          (2.0)          (1.2)          19.1  Adjusted EBITDAX  $     180.6   $    201.5   $    307.4   $    179.7   $    173.3   $    219.5  21
    • Penn Virginia Corporation4 Radnor Corporate Center, Suite 200Radnor, PA 19087610‐687‐8900www.pennvirginia.com