Third Quarter 2016 Earnings Conference Call & Webcast November 15, 2016

Transcription

1 Third Quarter 2016 Earnings Conference Call & Webcast November 15,

2 Forward-Looking Statements / Oil and Gas Reserves and Definitions Forward-Looking Statements Certain statements contained herein that are not descriptions of historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: potential adverse effects of the completed Chapter 11 proceedings on our liquidity, results of operations, brand, business prospects, ability to retain financing and other risks and uncertainties related to our emergence from Chapter 11; the ability to operate our business following emergence from Chapter 11; our ability to satisfy our short-term and long-term liquidity needs, including our inability to generate sufficient cash flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties; new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting; plans, objectives, expectations and intentions contained in this presentation that are not historical; our ability to become listed on the OTCQX or a national securities exchange; our ability to execute our business plan in the current depressed commodity price environment; the decline in and volatility of commodity prices for oil, natural gas liquids, or NGLs, and natural gas; our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the resumption of our drilling program; the projected demand for and supply of oil, NGLs and natural gas; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and natural gas reserves; drilling and operating risks; our ability to compete effectively against other oil and gas companies; leasehold terms expiring before production can be established and our ability to replace expired leases; environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key employees; counterparty risk related to the ability of these parties to meet their future obligations; compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; physical, electronic and cyber security breaches; litigation that impacts us, our assets or our midstream service providers; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the Securities and Exchange Commission (SEC). Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events, changed circumstances or otherwise. Oil and Gas Reserves 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. Investors are urged to consider closely the disclosure in Penn Virginia s Annual Report on Form 10 K for the fiscal year ended December 31, 2015, which is available from Penn Virginia St. Mary s Lane, Suite 275, Houston, Texas (Attn: Investor Relations). You can also obtain this report from the SEC by calling SEC 0330 or from the SEC s website at Definitions Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves, but which are as likely than not to be recoverable (there should be at least a 50% probability that the quantities actually recovered will equal or exceed the proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should be at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date and cumulative production as of that date. EUR is a measure that by its nature is more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly is less certain. Reconciliation of GAAP and Non-GAAP Financial Measures This presentation contains references to both GAAP and non-gaap financial measures. Reconciliations between GAAP and non-gaap financial measures are available in the appendix to this presentation. 1

3 Penn Virginia Today Successfully completed restructuring 100% of unsecured notes converted to equity New revolving credit facility 15.0 million shares outstanding High quality land position Multi-year inventory of Lower Eagle Ford drilling locations Upside potential from downspacing, Upper Eagle Ford, Austin Chalk Excellent well results Proven slickwater completion design 100% improvement in well productivity Strong liquidity $97 million of liquidity Option to accelerate drilling program Low Cost Operator 55% estimated reduction in G&A Focused Eagle Ford Operator 25% decline in LOE per BOE from 2014 to YTD 2016 San Antonio Approximate Location of Granite Wash Acreage Houston Approximate Location of Eagle Ford Acreage 2

4 Successful Restructuring 100% of senior unsecured notes and general unsecured claims converted to newly-issued common equity PVAC 15 million shares outstanding Listed on OTC Pink today Expect to trade on OTCQX by end of November Filing for listing on national securities exchange $50 million rights offering New revolving credit facility in place 3

5 Eagle Ford Acreage Map Contiguous Acreage in Northeast Section of the Trend 81,593 gross / 53,045 net Eagle Ford acres Net of 33,623 gross / 28,491 net non-core acres expiring by YE % held by production Penn Virginia Acreage Source: Shale Experts 4

6 Recent Activity in Gonzales and Lavaca Counties Slickwater Completions To Date and Offset Activity PVAC Sable Unit 4H : DUC 5H : DUC 6H : Surface Casing Set PVAC Hawg Hunter Unit 3H : IP 3,563 BOEPD 4H : IP 4,052 BOEPD 5H : IP 3,917 BOEPD Fayette Lavaca PVAC Washington Unit 2H : IP 1,668 BOEPD 3H : IP 1,802 BOEPD PVAC Munson Ranch Unit 11H : IP 800 BOEPD 12H : IP 638 BOEPD PVAC J. Berger Jr. Cattle Co. Unit 1H : IP 2,771 BOEPD PVAC Cinco J Ranch LTD Unit 3H : IP 2,015 BOEPD 4H : IP 1,617 BOEPD 5H : IP 2,166 BOEPD PVAC L & J Lee Unit 4H : IP 1,080 BOEPD 5H : IP 1,399 BOEPD 6H : IP 1,398 BOEPD PVAC Chicken Hawk Unit 1H : IP 2,898 BOEPD PVAC Bertha Unit 2H : IP 1,405 BOEPD 3H : IP 2,189 BOEPD 4H : IP 2,111 BOEPD Gonzales EOG Annie Unit 12H : IP 2,865 BOEPD EOG Zimmerman Unit 14H : IP 4,275 BOEPD 15H : IP 3,223 BOEPD DeWitt EOG Kasper Unit 1H : IP 3,586 BOEPD 2H : IP 1,473 BOEPD 3H : IP 2,464 BOEPD 4H : IP 2,727 BOEPD 16H : IP 2,994 BOEPD 17H : IP 2,505 BOEPD 18H : IP 2,605 BOEPD EOG Boedecker Unit 18H : IP 3,923 BOEPD 19H : IP 3,185 BOEPD Blue shading denotes non-core acreage expiring by YE hr IPs as reported to Texas RRC 5

7 Eagle Ford Operations Overview Focus on Oilier Part of the Play Operate 301 wells plus interest in 36 outside-operated wells Third quarter 2016 Eagle Ford production: 889 MBOE or 9,659 BOE per day High oil content, especially in Area 1 Total Production 8% 92% Eagle Ford Production Mix 10% 15% 75% Area 1 Slickwater Production Mix 8% 6% 86% Eagle Ford Granite Wash Oil NGLs Natural Gas Oil NGLs Natural Gas 6

8 Efficiency is Leading to Better Returns 1,700 Footage Drilled Per Day 1,600 1,500 Drilling efficiencies have increased 57% in three years 1,400 1,300 1,200 1,100 1,000 D&C costs 52% lower in that same time period Transition to slickwater and other design improvements have doubled productivity Targeting $800 per foot in D&C cost in YTD 2016 D&C Costs Continue to Decline 250 Slickwater Completions Yield Increased Production $2,000 Costs per Foot of Lateral $1,800 $1,600 $1,400 $1,200 $1,000 $800 $600 IP 30 (BOEPD) / 1,000 Feet of Lateral Hybrid $400 $200 $ YTD E 0 Q Q Q Q Q YTD

9 Over 50% Rate of Return at $50 Oil for Area 1 1,200 Area 1 Lower Eagle Ford Slickwater Type Curve 300 Total Well Cost AREA 1 TYPE CURVE $4.8 MM Daily Average Oil - BOPD 1, Months on Production Daily Oil Production (BOPD) Cumulative Oil Production (MBO) Cumulative Oil - MBO Frac Stages 24 Lateral Length Gross Oil Net EUR 6,000 feet 493 MBOE 422 MBO 370 MBOE ROR Oil Price ($/B) ROR (%) Economic Sensitivity of Area 1 Lower Eagle Ford Slickwater Well with 6,000' Lateral Rate of Return - % Avg Hawg Hunter Well (Normalized to 6,000 ') Slickwater Completion NYMEX Oil Price (Flat) - $/Bbl Gas Price: $3.00 Flat Previous Hybrid Completion 8

10 2017 Preliminary Guidance Plan to Spud 16 to 19 Net Wells in 2017 Preliminary 2017 CAPEX plan of $95 to $115 million, 85% on D&C capital 3,600 to 3,900 MBOE of total production expected in 2017, 70% to 72% from oil G&A: $16 to $19 million per year (1) LOE: $5.00 to $5.50 per BOE GPT: $2.90 to $3.30 per BOE $ millions $50 $40 $30 $20 $10 G&A Trend (1) Volume Profile $ E 2017E $10 LOE Trend Q Q Q Q Q Q $ per BOE $5 (1) Primary cash G&A. Excludes share and liability based compensation, and significant special charges. Q4 of 2016E and 2017E are estimated at midpoint of guidance. Actuals reconcile to amounts reported as Primary general and administrative expenses in the Company s MD&A for General administrative expenses. See non- GAAP reconciliation in Appendix $ YTD

11 Eagle Ford Development Plan Concentrate initial development in Area 1 Spudding third well on three-well Sable pad, turn to sales Q Moving to 3-well Axis pad in late Q4 2016, turn to sales Q Q / 2017 development plan: Q Q FY well Sable Pad 3-well Axis Pad 16 to 19 net wells spud 13 to 16 net wells turned to sales 10

12 FINANCIALS

13 Q Financial Overview For the combined Successor & Predecessor (1) periods of Q3 2016: Highlights ($ millions) Total Production (MBOE) 979 Total Product Revenues $33.3 Total Production per Day (BOEPD) 10,629 Cash Direct Operating Expenses (2) $19.6 Oil (MBbls) 674 Adjusted EBITDAX (3) $17.8 Oil Realized Price ($ per Bbl) $42.88 DD&A $10.1 Differential from WTI (4) ($2.06) Operating Income ($6.6) NGLs (MBbls) 160 NGLs Realized Price ($ per Bbl) $12.58 Reorganization Items, Net $1,152.4 Natural Gas (MMcf) 896 Natural Gas Realized Price ($ per Mcf) $2.72 Cash Hedge Proceeds $1.1 (1) References to "Successor" relate to the financial position and results of operations of the reorganized Penn Virginia from September 13, 2016 through September 30, References to "Predecessor" relate to the financial position of Penn Virginia before application of fresh start accounting prior to and including September 12, (2) G&A, LOE, Gathering, Processing & Transportation, Severance & Ad Valorem Taxes (3) Non-GAAP measure. See reconciliation in Appendix. (4) Calendar daily average 12

14 Strong Liquidity New revolving credit facility $200 million commitment Current Liquidity (as of November 11) $128 million borrowing base $140 $128 $54.4 million drawn at end of Q3 $39.0 million drawn at Nov 11 $120 $100 $39.0 Drawn $7.6 $96.6 $14.0 million cash at end of Q3 $7.6 million cash at Nov 11 $ Million $80 $60 $40 $89.0 Available $20 $0 Borrowing Base Cash Total Liquidity 13

15 Hedge Portfolio Well Hedged Through 2019 Oil Hedges Substantial portion of oil production is hedged using swaps Mark to market at quarter end was a net liability of $14.7 million Natural gas and NGL volumes are unhedged 7,000 6,000 5,940 $49.90 $50.50 $ ,000 4,000 3,000 4,408 $48.62 $ ,477 2,915 $49.50 $49.00 $48.50 $ ,000 $47.69 $ ,000 $ Q Hedged Volumes (BOEPD) (BOPD) Swap Swap Price Price ($ per Bbl) $

16 Conclusion Very attractive asset base in prime area of Eagle Ford Multi-year inventory of high rate of return drilling locations Upside potential Low cost producer Strong balance sheet and good liquidity provide option to accelerate Strong Balance Sheet Excellent Assets Positioned For Success 15

17 Q&A

18 Non GAAP Reconciliation Adj. EBITDAX ($ in thousands) Predecessor Successor Combined July 1 September 13 Three Months through through Ended September 12 September 30 September 30 Net income (loss) $ 1,150,055 $ (3,441) $ 1,146,614 Adjustments: Income tax benefit Reorganization items, net (1,152,373) - (1,152,373) Interest expense 1, ,581 Depreciation, depletion and amortization 8,024 2,029 10,053 Exploration 4,641-4,641 Share-based compensation (equity-classified) 5,433-5,433 Restructuring expenses (severance and retention) 2, ,740 Q Financial Overview Gains on sales of property (1) (504) - (504) Adjustments for derivatives: Net (gains) losses (8,934) 4,369 (4,565) Cash settlements 1,056-1,056 Subtotal for derivatives (7,878) 4,369 (3,509) Reserve for bad debts- JV partner receivables Other account write-offs prior to emergence 2,154-2,154 Adjusted EBITDAX $ 14,606 $ 3,193 $ 17,799 Adjusted EBITDAX represents net income (loss) before income tax benefit, interest expense, depreciation, depletion and amortization expense, exploration expense and share-based compensation expense, further adjusted to exclude the effects of non-cash changes in the fair value of derivatives, restructuring expenses, impairments, net gains and losses on the sale of assets, loss on extinguishment of debt and other non-cash items. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. 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 (loss). Adjusted EBITDAX as defined by Penn Virginia may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Penn Virginia s results as reported under GAAP. 17

19 Non GAAP Reconciliation G&A Expense General and Administrative Expense ($ in thousands) Year Ended December 31, YTD 3Q2016 General and administrative expense, as reported $ 49,005 $ 43,328 $ 40,421 Adjustments: Liability-classified share-based compensation (4,519) Equity-classified share-based compensation (3,627) (4,540) (1,511) Strategic and financial advisory costs - (6,189) (18,036) ERP system development costs Q Financial Overview (1) (1,154) - - Acquisition-related costs (589) - - Severance (10) (957) (3,839) Primary cash-based general and administrative expenses 1 39,106 32,353 17,054 (1) Reconciles to amounts reported as Primary general and administrative expenses in the Company s MD&A for General administrative expenses. We believe this presentation is useful to investors in analyzing the primary, recurring cash component of our total general and administrative expense as reported under GAAP. Cash-based general and administrative expenses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for an analysis of general and administrative expense as reported under GAAP. 18