First Quarter 2021 Earnings Presentation - May 4, 2021 - cloudfront.net
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First Quarter 2021 Earnings Presentation May 4, 2021
Forward-Looking and Cautionary Statements
This presentation contains “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. All statements,
other than statements of historical fact, included in this presentation that address activities, events or developments that Penn Virginia expects, believes or anticipates will or may occur in the future are forward-looking
statements. Words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “create,” “intend,” “could,” “would,” “may,” “plan,” “will,” “guidance,” “look,” “goal,” “future,” “build,” “focus,” “continue,”
“strive,” “allow” or the negative of such terms or other variations thereof and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements.
However, the absence of these words does not mean that the statements are not forward-looking. These forward-looking statements include, but are not limited to, (1) Penn Virginia’s future production and capital expenditures,
its ability to maintain low cost structure, the impact of Gulf Coast pricing, the benefits of its hedge positions and resumption of the drilling program, and its ability to manage leverage and operate within cash flow, and (2)
statements regarding the transactions with Juniper described herein (the “Transaction”) and as adjusted descriptions of the post-Transaction company and its operations, integration, debt levels, acreage, well performance,
development plans, per unit costs, ability to maintain production within cash flow, production, cash flows, synergies, type curves, opportunities and anticipated future performance. Information adjusted for the Transaction
should not be considered a forecast of future results. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this presentation. These
include the risk that changes in Penn Virginia’s capital structure and governance, including its status as a controlled company, could have adverse effects on the market value of its securities; the ability of Penn Virginia to
retain customers and retain and hire key personnel and maintain relationships with its suppliers and customers and on Penn Virginia’s operating results and business generally; the risk the Transaction could distract
management from ongoing business operations or cause Penn Virginia to incur substantial costs; the risk that the expanded acreage footprint does not allow for longer laterals, lower per unit operating expenses, and increased
number of wells per pad as expected; the ability of Penn Virginia to develop drilling locations, which do not represent oil and gas reserves, into production or proved reserves; the risk that Penn Virginia may be unable to reduce
expenses or access financing or liquidity; the risk that the Company does not realize expected benefits of its hedges; the impact of the COVID-19 pandemic, the related economic downturn and the related substantial decline in
demand for oil and natural gas; the risk of changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; and other important factors that could cause actual
results to differ materially from those projected. All such factors are difficult to predict and are beyond Penn Virginia’s control, including those detailed in Penn Virginia’s Annual Reports on Form 10-K, Quarterly Reports on
Form 10-Q and Current Reports on Form 8-K that are available on Penn Virginia’s website at www.pennvirginia.com and on the website of the Securities and Exchange Commission (the “SEC”) at www.sec.gov. All forward-
looking statements are based on assumptions that Penn Virginia believes to be reasonable but that may not prove to be accurate. Any forward-looking statement speaks only as of the date on which such statement is made,
and Penn Virginia undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Readers are cautioned
not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.
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. Proved developed reserves are proved reserves that can be expected to be recovered: (a) through existing wells with existing
equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or (b) through installed extraction equipment and infrastructure operational at the time
of the reserves estimate if the extraction is means not involving a well. 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.
Cautionary Statements
The estimates and guidance presented in this presentation, including those regarding inventory of drilling locations and expected free cash flow, are based on assumptions of capital expenditure levels, prices for oil, natural gas
and NGLs, current indications of supply and demand for oil, well results and operating costs. The guidance, estimates and type curves provided or used in this presentation do not constitute any form of guarantee or assurance
that the matters indicated will be achieved. Statements regarding inventory are based on current information, assumptions regarding well costs, the drilling program and economics and are subject to material change. The
number of locations shown as being in the Company’s current estimated inventory is not a guarantee of the number of wells that will actually be drilled and completed or the results or return that will be achieved. While we
believe these estimates and the assumptions on which they are based are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, operational and regulatory risks and
uncertainties and are subject to material revision. Actual results may differ materially from estimates and guidance. Market and competitive position data in this presentation has generally been obtained from industry
publications and surveys or studies conducted by third-party sources. There are limitations with respect to the availability, accuracy, completeness and comparability of such data. The Company has prepared this presentation
based on information available to it, including information derived from public sources that have not been independently verified, and no assurance can be given of its accuracy or completeness. Certain statements in this
document regarding the market and competitive position data are based on the internal analyses of the Company, which involve certain assumptions and estimates. These internal analyses have not been verified by any
independent sources, and there can be no assurance that the assumptions or estimates are accurate.
Reconciliation of Non‐GAAP Financial Measures
This presentation contains references to certain non‐GAAP financial measures. Reconciliations between GAAP and non‐GAAP financial measures are available in the appendix to this presentation. The non-GAAP financial
measures presented may not provide information that is directly comparable to that provided by other companies, as other companies may calculate such financial results differently. The Company's non-GAAP financial
measures are not measurements of financial performance under GAAP and should not be considered as alternatives to amounts presented in accordance with GAAP. The Company views these non-GAAP financial measures
as supplemental and they are not intended to be a substitute for, or superior to, the information provided by GAAP financial results.
2
PVAC Investment Thesis
Strong High Advantaged
Premier Strong
PDP Base Margin / Regulatory
Oil Balance
with Improving and
Weighted Sheet /
Substantial Infrastructure
Asset Efficiency Liquidity
Inventory Position
Focused on Cash-on-Cash Returns and Committed to Continuous Improvement
3
Company Overview
• NASDAQ: PVAC – Enterprise Value: $890 MM(1)
Eagle Ford
• 102,400 gross (90,400 net) acres(2) in Gonzales, Fayette, Lavaca and
DeWitt counties; ~100% Operated; 91% HBP
• Approximately 500 identified drilling locations in inventory
o Two-thirds of locations estimated to average 55%+ well level IRR
at $55/bbl WTI(3)
• 1Q21 Sales: 16,324 bbl/d and 20,534 boe/d; 80% oil / 91% liquids
• Top quartile adjusted EBITDAX(4)(5) margins for 2020 Houston (HQ)
• Net Debt(4) to LTM adjusted EBITDAX(4) ~1.5x(6)
• Advantaged regulatory position
o No Federal acreage; Assets on private fee lands in Texas Oil
• Located close to Gulf Coast Markets (MEH/LLS)
Condensate
Gas
o Advantaged pricing and market access
$39.99/WTI $2.16/MMBtu $55/WTI $2.50/MMBtu
4/1 Reserves Summary ($MM)
SEC Pricing(7) Pricing(7)
Proved Developed Producing PV-10(4) $533 $912
(4)
Total Proved PV-10 $713 $1,660
Proved Developed Producing PV-10 to Net Debt(4)(8) 1.5x 2.5x
1) As of 03/31/21 with share price as of 05/03/21; assumes the redemption of 225,481.09 shares of Series A Preferred Stock and 22,548,109 common units in a partnership subsidiary.
2) As of 03/31/21.
3) Estimated well level returns based on DeGolyer and MacNaughton ("D&M") type curves as of 01/01/21.
4) Adjusted EBITDAX, as further adjusted for the Juniper Transaction, Net Debt and PV-10 are non-GAAP financial measures that are defined and reconciled in the appendix of this presentation.
5) Source:FactSet. Companies include: APA, AR, BATL, BCEI, BRY, CDEV, CLR, CNX, COG, CPE, CRK, DVN, EOG, EQT, ESTE, FANG, LPI, MCF, MGY, MTDR, NOG, OXY, PDCE, PXD, QEP, RRC, SBOW, SM, SWN, WLL and XEC.
6) Leverage ratio is calculated by dividing Net Debt as of 03/31/21 by LTM Adjusted EBITDAX as of 03/31/21, as further adjusted for Juniper EBITDAX of ~$5 MM. 4
7) Based on reserve report from D&M as of 04/01/21.
8) Net Debt as of 03/31/21.
ESG is Integral to PVAC Business Model
Penn Virginia focuses on creating long-term value for its shareholders while ensuring it fosters a culture that is steadfast on
operational safety, environmental sustainability, social responsibility, and sound corporate governance
Environmental Social
• We are committed to protecting the environment and • Penn Virginia has a local focus for its charitable giving
believe this commitment benefits shareholders and all campaigns, supporting non-profits and other
constituents organizations serving communities in and around
Houston, Texas and in our area of operations
• Efforts to minimize impact are multi-faceted:
o Reducing air emissions • The Company and its employees donate their time and
o Minimizing the use of freshwater resources to a wide range of charities, organizations and
o Preventing spills activities
o Safeguarding local water supplies • Additionally, we regularly partner with counties in which
• We have not only reduced our operational impact but also we operate to repair roads, often donating the materials
improved efficiency, lowered costs and reduced risk for road repairs
• Efforts have resulted in a more stable and sustainable • In 2020, we also implemented a matching gift program
business
Governance
We leverage corporate governance practices that promote transparency, accountability and good decision making as a key
tenet to our long-term success. Public confidence and our reputation are valuable assets. Therefore, a core value is to conduct
business and to interact with employees, independent contractors, lessees, suppliers, governmental entities, the public and
our communities, in a responsible and ethical manner. Another core value is to provide employees and independent
contractors with safe working conditions in an environment conducive to initiative, creativity and job satisfaction. To promote
these values, our Board of Directors has adopted a Code of Business Conduct and Ethics and that and other important
governance documents and related information are available at the Company’s website.
5
Premier Oil Asset in the U.S.
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
Premier Oil Asset in U.S.
• Proven geology with strong well-level economics; one of the oiliest Bakken
E&Ps with significant exposure to oil price recovery
• Eagle Ford Shale position with hundreds of drilling locations on
held-by-production acreage
• Robust production base with low corporate declines (2021 PDP oil
decline of 34%)(1) Denver
• Located on private fee lands in Texas near Gulf Coast for Julesburg
Basin
advantageous takeaway and product pricing
Highest % Oil Production(2) vs. Select Eagle Ford Operators Fayette
Gonzales Lavaca
De Witt
Permian
Basin
80%
64% 63%
50% 49% 47%
14% Shale Oil Basin Eagle Ford
Basin Shale Oil Basin
Company A Company B Company C Company D Company E Company F
Basin
Note: Eagle Ford Operators reflected in the % oil production graph include: CPE, LONE, MGY, SBOW, SM and SNDE.
1) Based on 2020 YE D&M Reserve Report. Decline is calculated from January 2021 to January 2022. 6
2) Eagle Ford operators’ production figures reflect 2020 data. Penn Virginia data reflect 1Q21. Source: FactSet.Strong PDP Base
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
Strong PDP Base with Substantial Inventory
• Concentrated position allows for operational
efficiencies
• Proven productivity across acreage position
• Expected PDP decline of 34%(1) provides
cash flow and flexibility
• Continually analyzing assets for cost
reductions and efficiency improvements
• Premium sweet crude oil with blended yield
of ~44 degree API gravity
• Strong PDP PV-10(2)(3) to Net Debt(3)(4) ratio
of 2.5x(5)
1) Based on expectations from type curves as set forth in 2020 YE D&M Reserve Report. Decline is calculated from January 2021 to January 2022.
2) Based on reserve report from D&M as of 04/01/21, using flat pricing of $55/bbl WTI, $2.50/MMbtu and NGLs as 36% of WTI. Differentials used ($2.50) off WTI and ($0.05) off natural gas.
3) Net Debt and PV-10 are non-GAAP measures reconciled in the appendix of this presentation. 7
4) Net Debt as of 03/31/21.
5) Ratio is calculated by dividing proved developed producing (“PDP”) PV-10 as of 04/01/21 by Net Debt as of 03/31/21.Exceptional Well Results and Deep Inventory
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
D&M Avg. Oil Type Curve for 2021 and 2022 TILs (BBL/d)
Fayette
TEXAS
10,000
Oil BBL/d ~ Matocha
1H: IP-30 1,248 bbl/d
Wells TIL YTD Actual Avg IP-30 Nevels Addax CLL: 8,568’
1,000
* Normalized for Lateral Length
~1,100 bbl/d
1H: IP-30 832 bbl/d
CLL: 6,298’
Gonzales
NAB Hunter
100 1H: IP-30 1,206 bbl/d
CLL: 9,510’
10 Munson Ranch
0 10 20 30 40 50 60 70 80 90 100 110 13H: IP-30 1,310 bbl/d Lombardo Unit
Months CLL: 8,130’ 2H: IP-30 1,102 bbl/d
14H: IP-30 801 bbl/d CLL: 5,652’
2020 Outperformance and Future Inventory CLL: 6,039’
13H: IP-30 1,216 bbl/d
• CLL: 6,743’ Javelina (PSA)
D&M total inventory of ~500 locations A1H: IP-30 1,150 bbl/d
CLL:7,822
o Two-thirds of locations estimated to average 55%+ B2H: IP-30 1,126 bbl/d
well level IRR at $55/bbl WTI(3) Southern Bock (PSA) CLL: 6,604’
A1H: IP-30 1,676 bbl/d
• 2020 spud wells currently outperforming D&M projections by
CLL:6,381’
B2H: IP-30 1,405 bbl/d
Lavaca
~13% on a cumulative basis CLL: 8,349’
Blonde Unit
• 2021 TIL wells IP-30 currently outperforming D&M type 2H: IP-30 1,040 bbl/d
CLL: 5,920’
ACREAGE
curves by over 20% PVAC
RECENTLY ACQUIRED
EAGLE FORD PEERS
De Witt
• Relatively open undrilled lease geometries allow for long
laterals and efficient multi-well pads
1) Type curve assumptions are estimates based on 2020 YE D&M Reserve Report and on management’s internal estimates as of 05/04/21.
2) Capital expenditure assumptions include Drilling, Completion, Facilities, and Tie-in expenditures. Average Drilling and Completion capital of ~$5.75 MM per well plus $0.5 MM for Facilities and Tie-in expenditures for Total Capex
of $6.25 MM. 8
3) Estimated well level returns based on D&M type curves as of 01/01/21.Continuously Improving Drilling Efficiencies
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
Total Well Cost by Spud Date - $/Lateral Foot(1) Total Well Cost per boe of Reserves Developed(1)
Total Well Cost Include Drilling, Completion, Facilities and Tie-in Expenditures Total Well Cost Include Drilling, Completion, Facilities and Tie-in Expenditures
$1,206 $17.49 $17.23
$1,079
$14.25
$875
2018 2019 2020 2018 2019 2020
1) Reserves based on D&M 2020 YE Reserve Report.
9Driving Down Costs
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
• 2020 LOE per boe declined by ~27% from 2017
• 2020 Adjusted Cash G&A(1) per boe declined by ~22% from 2017
Focused on Costs
$14.40
$11.99
$11.36 $11.28
2017 2018 2019 2020
Adjusted Direct Operating Expenses per boe(1)(2)
1) Adjusted Cash G&A per boe and Adjusted Direct Operating Expenses per boe are non-GAAP financial measures. Definitions of non-GAAP financial
measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear in the appendix of this presentation.
2) Adjusted Direct Operating Expenses per boe is comprised of the sum of (Lease Operating Expense + GPT Expense + Adjusted Cash G&A Expense(1) +
10
Production and Ad Valorem Taxes)/Total Production.While Expanding Margins
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
Increased Adjusted EBITDAX(1) Margin in the Face of Dramatic Decline in Oil Prices
Margin/WTI
WTI Price
70%
59% 60%
53%
$64.89
$57.04
$50.86
$42.62
$38.44
$34.17
$29.89
$26.88
2017 2018 2019 2020
Note: Adjusted EBITDAX Margin = Adjusted EBITDAX per boe/WTI Price.
1) Adjusted EBITDAX per boe is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial 11
measures appear in the appendix of this presentation.Peer Leading Margins
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
Gulf Coast Pricing + Low Cost Adjusted EBITDAX per boe
= Strong Margin(1) PVAC vs. Peer U.S. Public Operators(2)
Realized Aggregate Price $47.79/boe
~$30
Margin $34.23/boe
Adj G&A
Prod Taxes
GPT
LOE
Q121
Notes: Companies: APA, AR, BATL, BCEI, BRY, CDEV, CLR, CNX, COG, CPE, CRK, DVN, EOG, EQT, ESTE, FANG, LPI, MCF, MGY, MTDR, NOG, OXY, PDCE, PXD, QEP, RRC, SBOW, SM, SWN, WLL and XEC.
Source: Peer data from FactSet: Adjusted EBITDAX per boe is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial
measures appear in the appendix of this presentation.
1) Margin is defined as realized aggregate price less adjusted direct operating expenses.
2) For the year-ended 12/31/20.
12Committed to Strong Balance Sheet
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
No Near-Term Debt Maturities
Net Debt Maturity Profile(1) $MM Capitalization(3)
MM, except share price
Net Revolver Outstanding $364 Total Stock Outstanding(3) 37.9
2nd Lien Term Loan Share Price (as of 05/03/2021) $13.91
$217 (2) Market Capitalization(3) $527
Plus: Total Debt(4) $376
$147 Less: Cash(4) ($12)
Enterprise Value $890
2020 2021 2022 2023 2024
Nearest maturity occurs in 2024
Liquidity(4)(5) $133
1) Net Debt as of 03/31/21.
2) Net of cash as of 03/31/21.
3) Assumes the redemption of 225,481.09 shares of Series A Preferred Stock and 22,548,109 common units in a partnership subsidiary. As of 03/31/21, there were 15,309,821 shares of common stock outstanding. 13
4) As of 03/31/21.
5) Liquidity represents undrawn credit facility plus cash less letters of credit.Committed to Strong Balance Sheet
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
LTM Net Leverage(1) LTM Net Leverage(1) vs. Peer U.S. Public Operators(4)
1.9x
1.5x(2)
12/31/20 03/31/21
Liquidity(3)
$133MM
1.5x(2)
$48MM
03/31/21
12/31/20 03/31/21
Notes: U.S. onshore E&P companies: BATL, BRY, CDEV, CPE, ESTE, GDP, MGY, NOG, QEP, SBOW, SM and SNDE. Source: Peer data from FactSet: Net debt as of 12/31/20 and LTM Adjusted EBITDAX. The figures are provided for information purposes only and should not be relied upon in making an
investment decision. Penn Virginia’s Net Debt as of 03/31/21 and LTM adjusted EBITDAX as of 03/31/21, as further adjusted for Juniper EBITDAX of ~$5 MM. Net debt and LTM adjusted EBITDAX are non-GAAP measures defined and reconciled to the closest GAAP-based financial measures in the
appendix of this presentation.
1) Leverage ratio is calculated by dividing Net Debt by LTM adjusted EBITDAX. Net Leverage is a non-GAAP measure defined and reconciled to the closest GAAP-based financial measures in the appendix of this presentation.
2) Leverage ratio is calculated by dividing Net Debt as of 03/31/21 by LTM Adjusted EBITDAX as of 03/31/21 as further adjusted for Juniper EBITDAX of ~$5 MM. Net Leverage is a non-GAAP measure defined and reconciled to the closest GAAP-based financial measures in the appendix of this presentation. 14
3) Liquidity represents undrawn credit facility plus cash less letters of credit.
4) As of 12/31/20. Source: FactSet Peers include: APA, AR, BATL, BCEI, BRY, CDEV, CLR, CNX, COG, CPE, CRK, DVN, EOG, EQT, ESTE, FANG, LPI, MCF, MGY, MTDR, NOG, OXY, PDCE, PXD, QEP, RRC, SBOW, SM, SWN, WLL and XEC.Advantaged Regulatory Position
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
State of Texas one of the friendliest to oil and gas industry
Operating Long track record of treating mineral rights as firm property rights
Environment Landowners are often mineral rights owners, incentivized to allow access and development
No federal acreage exposure
Acreage ~100% private landholder leases
91% held by production status
Direct access to Gulf Coast markets
Infrastructure Minimizes dependency on interstate federal regulated infrastructure
Limited infrastructure permitting risk
Robust infrastructure and processing facilities reduce need for flaring
Majority of production on pipeline, limiting emissions and spill occurrence
Optical gas imaging cameras used to scan production facilities for leaks as part of leak
Emissions
detection and repair program
Emission control equipment, such as vapor recovery towers (VRT), combustors, and low-
pressure flares, that minimize natural gas flaring
15Substantial Infrastructure – Advantaged Pricing
Premier Oil Strong PDP Base with High Margin / Strong Balance Advantaged Regulatory and
Weighted Asset Substantial Inventory Improving Efficiency Sheet / Liquidity Infrastructure Position
Location Close to Coast with Attractive Sales Points
• 1Q21 Sales: 80% Oil; 91% 1Q21 Sales Mix 35 Caldwell
Fayette
610 10
Liquids 10 Colorado Fort Bend Chambers
• Receives MEH Pricing, 9%
80%
Gonzales Lavaca
45
Premium Over WTI and 11% Wharton
Wilson
Midland Jackson
Brazoria
•
De Witt
Realized $44.80 per bbl in Karnes
1Q21(1)
Matagorda
Victoria
•
Goliad
Freeport
Blended Oil Yields LNG Facility
~44 Degree API Gravity Bee Calhoun
Live Oak Refugio To San Antonio To Houston
Oil 37 Acreage 10
NGLs San
PVAC
Oil Pipelines Fayette
Natural Gas Patricio Nuevo – Dewitt Line
Nuevo – Main Gathering
Gas Pipelines
Jim Wells Nueces ETC Lines
LLS vs. WTI vs. MEH and Midland Pricing Kinder Morgan Lines
PVAC Gathering Lines
Corpus Christi
Corpus Starwood Lines
$3 Kleberg
Christi
LLS $2.20 LNG Facility
$2 Lavaca
MEH $1.06 Brooks
Gonzales
$1 Kenedy
Mid $0.51
$0
WTI Hidalgo Willacy
De Witt
-$1 Jan '21 Feb '21 Mar '21
Note: Map data provided by and used with permission of Hart Energy Mapping and Data Services, LLC.
1) Realized oil price, including effects of derivatives, net is a non-GAAP measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end
of this release.
162021 Strategic Focus
Cash-on-Cash Returns
• Maximize value of each bbl and Mcf sold
• Scrutinize risk-adjusted returns on capital deployment
Committed to Continuous Improvement
• Streamline operations and processes
• Search for cost savings and operational improvements
• Focused on ESG
Align Compensation with Shareholder Returns
• Cash bonuses to be based on current-year cost and returns-based metrics
• Long-term compensation to be based on long-term return-based metrics
Maintain Healthy Balance Sheet
• Continue free cash flow(1) generation
• Keep leverage level low with substantial liquidity
1) Free Cash Flow is a non-GAAP financial measure that is defined and reconciled in the appendix of this presentation.
172021 Increased Guidance
2021 Oil Sale Volumes Guidance – bbl/d
o Expect to maintain current 2-rig program while closely
monitoring commodity prices and costs 18,300-20,100
o Will continue to monitor service cost environment to ensure
capital program generates robust returns and free cash
flow(1) 17,200-19,000
o D&C Capex between $205 MM and $235 MM for 2021(2) Previous Revised
o Approximately $5 MM of land, facilities and other Sales 2Q21 Current 2021 Prior 2021
o D&C Capex between $56 MM and $64 MM for 2Q21(2) Oil Sales -
19,300 – 20,100 18,300 – 20,100 17,200 – 19,000
bbl/d
o Approximately $1 MM of land, facilities and other Direct Operating Expense 2Q21 2021
Lease Operating Expense (per boe) $4.70 - $4.90 $4.70 - $5.00
GPT Expense (per boe) $2.55 - $2.75 $2.35 - $2.65
Ad Valorem and production taxes 6.3% - 6.8% 6.3% - 6.8%
Adj. Cash G&A expense (per boe)(3) $3.00 - $3.30 $2.85 - $3.15
o Focus on returns and capital efficiency
Realized Pricing Differentials 2Q21 2021
o Continue free cash flow(1) generation
Oil (WTI, per bbl) $(2.50) - $(1.50) $(2.50) - $(1.50)
Natural gas (HHub, per MMBtu) $(0.10) - $0.10 $(0.10) - $0.10
Focused on Cash-on-Cash Returns and Committed to Continuous Improvement
Note: Guidance as of 05/04/21. All guidance are estimates as of the date hereof and is subject to change without notice depending upon a number of factors, including commodity prices, industry conditions and other factors that are beyond the
Company’s control. The Company undertakes no obligation to affirm or update its guidance.
1) Free cash flow is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear in the appendix of this presentation. 18
2) Based on $50 per bbl WTI capital environment.
3) Full-year 2021 guidance for Adjusted Cash G&A does not include ~$5 million of Juniper transaction expenses.PVAC Investment Thesis
Strong Advantaged
Premier High Strong
PDP Base Regulatory
Oil Margin / Balance
with and
Weighted Improving Sheet /
Substantial Infrastructure
Asset Efficiency Liquidity
Inventory Position
Focused on Cash-on-Cash Returns and Committed to Continuous Improvement
19Appendix
Focus on Risk Management with Oil Price Upside
Mitigating Commodity Price Volatility Through Proactive Hedging Program
$44.65 - $55.10
16,000
$44.27 - $56.53
14,000
12,000
$42.00 - $54.92
Oil Barrels Per Day
10,000
8,000
$40.00 - $52.47
6,000 $40.00 - $53.49
4,000
$55.89
2,000
$45.54 $45.54
0
2Q'21 3Q'21 4Q'21 1Q'22 2Q'22 3Q'22 4Q'22
Collar (WTI) Swap (WTI)
Note: As of 05/03/21. 1.35 MMbbl are subjected to sold put options with an average strike price of approximately $33.96 per bbl. See next slide for more detail.
21
.Commodity Hedge Summary – Quarterly(1)
2Q'21 3Q'21 4Q'21 1Q'22 2Q'22 3Q'22 4Q'22 1Q'23 2Q'23
Hedges
WTI Swaps (bbl/d) 3,297 815 815 – – – – – –
WTI Average Fixed Price ($/bbl) $55.89 $45.54 $45.54 – – – – – –
WTI Collars (bbl/d) 12,637 14,130 9,783 5,417 4,533 4,484 4,484 2,917 2,885
WTI Average Purchased Put ($/bbl) $44.65 $44.27 $42.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00
WTI Average Sold Call ($/bbl) $55.10 $56.53 $54.92 $53.49 $52.47 $52.47 $52.47 $50.00 $50.00
WTI Net Sold Puts (bbl/d) 4,945 5,707 5,707 – – – – – –
WTI Net Average Sold Put ($/bbl) $29.83 $35.14 $35.14 – – – – – –
WTI CMA Roll Swaps (bbl/d) 18,132 17,935 17,935 – – – – – –
WTI CMA Roll Average Fixed Price ($/bbl) $0.17 $0.17 $0.17 – – – – – –
HH Collars (MMbtu/d) 9,890 9,783 9,783 – – – – – –
HH Average Purchased Put ($/MMbtu) $2.61 $2.61 $2.61 – – – – – –
HH Average Sold Call ($/MMbtu) $3.12 $3.12 $3.12 – – – – – –
HH Sold Puts (MMbtu/d) 6,593 6,522 6,522 – – – – – –
HH Average Sold Put Strike ($/MMbtu) $2.00 $2.00 $2.00 – – – – – –
Ethane Swaps (Gal/d) 36,264 35,870 – – – – – – –
Ethane Average Fixed Price ($/Gal) $0.23 $0.23 – – – – – – –
1) As of 05/03/21.
22DR
Financial Targets and Metrics
Live Within Cash Flow on an Annual Basis
Generate Capital returns to be protected with hedging
Predictable
Matching cost and revenue terms to ensure consistent and predictable return profile
Returns
Match Short and RBL to be used as true working capital facility and not used as long term debt facility
Long-term
Maximizes liquidity protection to minimize impact of downside risk in commodity cycle
Liabilities
Focus on cash flowing collateral coverage and liquidity
Leverage and Maintain strong PDP PV-10(1) / Net Debt(1) coverage through all cycles
Balance Sheet Net Debt(1) / Adjusted EBITDAX(1) ofReconciliation of GAAP "Net Income" to Non-GAAP
"Adjusted EBITDAX"
Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Adjusted EBITDAX"
Adjusted EBITDAX represents net income (loss) before loss on extinguishment of debt, interest expense, income taxes, impairments of oil and gas properties, depreciation, depletion and amortization
expense and share-based compensation expense, further adjusted to include the net commodity realized settlements of derivatives and exclude the effects of gains and losses on sales of assets, non-cash
changes in the fair value of derivatives, and special items including acquisition, divestiture and strategic transaction costs, organizational restructuring, including severance and other items, executive
retirement costs, other, reorganization items and restructuring expenses. We believe this presentation is commonly used by investors and professional research analysts for the valuation, comparison, rating,
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 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.
Year Ended December 31,
1Q'21 1Q'21 LTM 2020 2019 2018 2017
(in thousands, except per boe amounts)
Net income (loss) $ (20,021) $ (493,672) $ (310,557) $ 70,589 $ 224,785 $ 32,662
Adjustments to reconcile to Adjusted EBITDAX:
Loss on extinguishment of debt 1,231 1,231 - - - -
Interest expense, net 5,397 28,474 31,257 35,811 26,462 6,392
Income tax (benefit) expense (310) (3,751) (2,303) 2,137 523 (4,943)
Impairments of oil and gas properties 1,811 393,660 391,849 - - -
Depreciation, depletion and amortization 23,884 123,839 140,673 174,569 127,961 48,649
Share-based compensation expense (equity-classified) 2,246 4,674 3,284 4,082 4,618 3,809
(Gain) loss on sales of assets, net (4) (16) (18) (5) 177 36
Adjustments for derivatives: -
Net losses (gains) 44,368 107,065 (88,422) 68,131 (37,427) 17,819
Realized commodity settlements, net 1 (16,059) 61,740 93,430 (10,501) (42,447) (4,175)
Adjustment for special items: -
Acquisition, divestiture and strategic transaction costs 4,655 9,628 4,973 800 3,960 1,340
Organizational restructuring, including severance 239 1,685 1,446 - - (20)
Executive retirement costs - - - - 250 -
Other, net - - - 232 (193) -
Reorganization items, net - - - - (3,322) -
2
Adjusted EBITDAX $ 47,437 $ 234,557 $ 265,612 $ 345,845 $ 305,347 $ 101,569
Net income (loss) per boe $ (10.83) $ (59.47) $ (34.95) $ 6.97 $ 28.30 $ 8.64
Adjusted EBITDAX per boe $ 25.67 $ 28.25 $ 29.89 $ 34.17 $ 38.44 $ 26.88
1
Realized commodity settlements, net includes, as applicable to the period presented: (i) current period commodity derivative settlements; (ii) the impact of option
premiums paid or received in prior periods related to current period production; (iii) the impact of prior period cash settlements of early-terminated derivatives originally
designated to settle against current period production; (iv) the exclusion of option premiums paid or received in current period related to future period production; and
(v) the exclusion of the impact of current period cash settlements for early-terminated derivatives originally designated to settle against future period production.
2
Excludes Adjusted EBITDAX adjustments of approximately $5 million attributable to oil and gas properties contributed by Rocky Creek Resources/Juniper.
24Reconciliation of GAAP “Operating Expenses” to Non-
GAAP "Adjusted direct operating expenses per boe"
Reconciliation of GAAP "Operating Expenses" to Non-GAAP "Adjusted direct operating expenses per boe"
Adjusted direct operating expenses and adjusted direct operating expenses per boe are supplemental non-GAAP financial measures that exclude certain non-recurring expenses and non-cash expenses. We
believe that the non-GAAP measure of Adjusted total direct operating expense per boe is useful to investors because it provides readers with a meaningful measure of our cost profile and provides for greater
comparability period-over-period.
Year Ended December 31,
1Q'21 2020 2019 2018 2017
(in thousands, except per boe amounts)
Operating expenses - GAAP $ 57,884 $ 642,443 $ 294,395 $ 232,077 $ 108,182
Less:
Share-based compensation - equity-classified awards (2,246) (3,284) (4,082) (4,618) (3,809)
Impairments of oil and gas properties (1,811) (391,849) - - -
Depreciation, depletion and amortization (23,884) (140,673) (174,569) (127,961) (48,649)
Total cash direct operating expenses 29,943 106,637 115,744 99,498 55,724
Significant special charges:
Acquisition, divestiture and strategic transaction costs (4,655) (4,973) (800) (3,960) (1,340)
Organizational restructuring, including severance (239) (1,446) - - 20
Executive retirement costs - - - (250) -
Non-GAAP Adjusted direct operating expenses $ 25,049 $ 100,218 $ 114,944 $ 95,288 $ 54,404
Operating expenses per boe $ 31.32 $ 72.29 $ 29.09 $ 29.21 $ 28.63
Total cash direct operating expenses per boe $ 16.20 $ 12.00 $ 11.44 $ 12.52 $ 14.75
Non-GAAP Adjusted direct operating expenses per boe $ 13.55 $ 11.28 $ 11.36 $ 11.99 $ 14.40
25Reconciliation of GAAP "General and Administrative Expenses" to
Non-GAAP "Adjusted Cash General and Administrative Expenses"
Reconciliation of GAAP "General and Administrative Expenses" to Non-GAAP "Adjusted Cash General and Administrative Expenses"
Adjusted cash general and administrative expenses is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash share-based
compensation expense. We believe that the non-GAAP measure of Adjusted cash general and administrative expenses is useful to investors because it provides readers with a
meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period.
Year Ended December 31,
1Q'21 2020 2019 2018 2017
(in thousands, except per boe amounts)
General and administrative expenses - direct $ 10,931 $ 30,505 $ 21,402 $ 21,446 $ 14,392
Share-based compensation - equity-classified awards 2,246 3,284 4,082 4,618 3,809
GAAP General and administrative expenses 13,177 33,789 25,484 26,064 18,201
Less: Share-based compensation - equity-classified awards (2,246) (3,284) (4,082) (4,618) (3,809)
Significant special charges:
Acquisition, divestiture and strategic transaction costs (4,655) (4,973) (800) (3,960) (1,340)
Organizational restructuring, including severance (239) (1,446) - - 20
Executive retirement costs - - - (250) -
Non-GAAP Adjusted cash general and administrative expenses $ 6,037 $ 24,086 $ 20,602 $ 17,236 $ 13,072
GAAP General and administrative expenses per boe $ 7.13 $ 3.80 $ 2.52 $ 3.28 $ 4.82
Non-GAAP Adjusted cash general and administrative expenses per boe $ 3.27 $ 2.71 $ 2.04 $ 2.17 $ 3.46
26Reconciliation of GAAP "Realized prices" to Non-GAAP
"Realized prices, including effects of derivatives, net"
Reconciliation of GAAP "Realized prices" to Non-GAAP "Realized prices, including effects of derivatives, net"
We present our realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net as we believe these measures are useful to management and stakeholders in determining the
effectiveness of our price-risk management program that is designed to reduce the volatility associated with our operations. Realized prices for crude oil and natural gas, as adjusted for the effects of
derivatives, net, are supplemental financial measures that are not prepared in accordance with generally accepted accounting principles (“GAAP”). The following table presents the calculation of our
non-GAAP realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net and reconciles to realized prices for crude oil and natural gas determined in accordance with
GAAP:
Three Months Ended
March 31, December 31, March 31,
2021 2020 2020
Crude oil realized price ($/bbl) $ 55.76 $ 39.66 $ 45.90
Effect of derivatives ($/bbl) $ (10.96) $ 9.18 $ 8.25
Crude oil realized price, including effects of derivatives, net ($/bbl) $ 44.80 $ 48.84 $ 54.15
Natural gas realized price ($/M cf) $ 2.80 $ 2.45 $ 1.83
Effect of derivatives ($/M cf) $ 0.04 $ (0.50) $ 0.07
Natural gas realized price, including effects of derivatives, net ($/M cf) $ 2.84 $ 1.95 $ 1.90
Aggregate realized price ($/boe) $ 47.79 $ 33.61 $ 37.35
Effect of derivatives ($/boe) $ (8.69) $ 6.85 $ 6.43
Aggregate realized price, including effects of derivatives, net ($/boe) $ 39.10 $ 40.46 $ 43.78
Effects of derivatives includes, as applicable to the period presented: (i) current period commodity derivative settlements; (ii) the impact of option
premiums paid or received in prior periods related to current period production; (iii) the impact of prior period cash settlements of early-terminated
derivatives originally designated to settle against current period production; (iv) the exclusion of option premiums paid or received in current period
related to future period production; and (v) the exclusion of the impact of current period cash settlements for early-terminated derivatives originally
designated to settle against future period production.
27Non-GAAP Reconciliation – Free Cash Flow ("FCF")
Definition and Explanation of Free Cash Flow
Free Cash Flow is a non-GAAP financial measure that management believes illustrates our ability to generate cash flows from our business that are available to be returned to our providers of financing capital
represented primarily by our debt holders as we do not currently have a dividend or share repurchase program. We present Free Cash Flow as the excess (deficiency) of discretionary cash flow over Capital
additions, net. Discretionary cash flow is defined as Adjusted EBITDAX (non-GAAP measure defined and reconciled to GAAP net income above) less interest expense, adjustments for income taxes refunded,
debt issue costs and changes for working capital and other, net. Capital additions represent our committed capital expenditure and acquisition transactions, net of any proceeds from the sales or disposition of
assets. We believe Free Cash Flow is commonly used by investors and professional research analysts for the valuation, comparison, rating, investment recommendations of companies in many industries. Free
Cash Flow should be considered as a supplement to net income as a measure of performance and net cash provided by operating activities as a measure of our liquidity.
Three Months Twelve Months
Ended Ended
March 31, 2021 March 31, 2021
(in thousands)
Adjusted EBITDAX, as reported $ 47,437 $ 234,557
Interest expense, as reported, less non-cash interest (5,632) (27,438)
Income taxes refunded - 2,471
Debt issue costs paid (1,830) (1,908)
Working capital and other, net 20,020 (53,622)
Discretionary cash flows 59,995 154,060
Capital expenditures, as reported (54,122) (105,510)
Proceeds from asset sales 4 16
Sales and use tax refunds applied to capital additions 425 425
Capital additions, net (53,693) (105,069)
Non-GAAP Free Cash Flow $ 6,302 $ 48,991
As adjusted net debt at beginning of period 1 $ 370,194 $ 412,883
Less: Historical net debt at end of period (363,892) (363,892)
Non-GAAP Free Cash Flow $ 6,302 $ 48,991
1
Net debt at the beginning of the period has been adjusted for the net cash effects of the Transaction and
debt amendments. See following table for adjustments attributed to the Juniper transaction and debt
amendments.
28Definition of Net Debt
Net Debt
Net debt, excluding unamortized discount and debt issuance costs is a non-GAAP financial measure that is defined as total principal amount of long-term debt less cash and cash
equivalents. Net debt, as adjusted, calculated on a pro forma basis as of December 31, 2020 and March 31, 2020 to adjust for related impacts of the Transaction (refer to footnote
1 below). The most comparable financial measure to net debt, excluding unamortized discount and debt issuance costs under GAAP is principal amount of long-term debt. Net
debt is used by management as a measure of our financial leverage. Net debt, excluding unamortized discount and debt issuance costs should not be used by investors or others
as the sole basis in formulating investment decisions as it does not represent the Company’s actual GAAP indebtedness.
March 31, 2021 December 31, 2020 March 31, 2020
1
Actual Pro Forma Adjusted Actual Pro Forma Adjusted 1
(in thousands)
Credit Facility $ 228,900 $ 314,400 $ 233,900 $ 399,400 $ 318,900
Second Lien term loan, excludes unamortized discount and issue costs 146,860 200,000 148,735 200,000 148,735
Cash and cash equivalents (11,868) (13,020) (12,441) (55,331) (54,752)
Net Debt $ 363,892 $ 501,380 $ 370,194 $ 544,069 $ 412,883
1
Adjustments attributable to the Transaction and debt amendments include (i) prepayments of $80.5 million under the Credit Facility; (ii) prepayments of $51.3
million under the Second Lien term loan and (iii) transaction expenses of $0.6 million paid in excess of the $150 million received as a capital contribution from Juniper
used to fund the prepayments and transaction expenses.
29Non-GAAP Reconciliation – "PV-10"
Reconciliation of GAAP "Standardized Measure of Discounted Future Net Cash Flows" to Non-GAAP "PV-10"
Non-GAAP PV-10 value is the estimated future net cash flows from estimated proved reserves discounted at an annual rate of 10 percent before giving effect
to income taxes. The standardized measure of discounted future net cash flows is the after-tax estimated future cash flows from estimated proved reserves
discounted at an annual rate of 10 percent, determined in accordance with generally accepted accounting principles (GAAP). We use non-GAAP PV-10 value
as one measure of the value of our estimated proved reserves and to compare relative values of proved reserves amount exploration and production
companies without regard to income taxes. We believe that securities analysts and rating agencies use PV-10 value in similar ways. Our management believes
PV-10 value is a useful measure for comparison of proved reserve values among companies because, unlike standardized measure, it excludes future income
taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves
themselves.
April 1,
2021
(in millions)
Standardized measure of future discounted cash flows $ 705
Present value of future income taxes discounted at 10% 8
PV-10 $ 713
30Reconciliation of PV-10 and Adjusted PV-10 (Non-GAAP) –
Proved Developed Producing Reserves and Total Proved
Reconciliation of PV-10 and Adjusted PV-10 (Non-GAAP) – Proved Developed Reserves (“PDP”)
Non-GAAP PV-10 value is the estimated future net cash flows from estimated proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes.
The standardized measure of discounted future net cash flows is the after-tax estimated future cash flows from estimated proved reserves discounted at an annual rate of 10
percent, determined in accordance with generally accepted accounting principles (GAAP). We use non-GAAP PV-10 value as one measure of the value of our estimated proved
reserves and to compare relative values of proved reserves amount exploration and production companies without regard to income taxes. We believe that securities analysts
and rating agencies use PV-10 value in similar ways. Our management believes PV-10 value is a useful measure for comparison of proved reserve values among companies
because, unlike standardized measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature,
location and quality of the reserves themselves.
April 1,
2021
(in millions)
Standardized measure of future discounted cash flows (total proved reserves) $ 705
Less: Future discounted cash flows attributable to proved undeveloped reserves (178)
Standardized measure of future discounted cash flows (proved developed producing reserves) 527
Add: Present value of future income taxes attributable to proved developed producing reserves discounted at 10% 6
PV-10 of proved developed producing reserves $ 533
Add: Adjustment using flat pricing of $55/BBL WTI, $2.50/MMbtu and NGLs as 36% of WTI PDP reserves. Differentials of
($2.50) off WTI and ($0.05) off natural gas. 379
Adjusted PV-10 of proved developed producing reserves adjusted for pricing and differentials $ 912
Reconciliation of PV-10 and Adjusted PV-10 (Non-GAAP) – Total Proved Reserves
April 1,
2021
(in millions)
Standardized measure of future discounted cash flows (total proved reserves) $ 705
Present value of future income taxes discounted at 10% 8
PV-10 of total proved $ 713
Add: Adjustment using flat pricing of $55/BBL WTI, $2.50/MMbtu and NGLs as 36% of WTI. Differentials of ($2.50) off WTI
and ($0.05) off natural gas. 947
Adjusted PV-10 of total proved reserves adjusted for pricing and differentials $ 1,660
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