MAY UPDATEMay 2018

Forward Looking Statements

May 2018 2

This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"), and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements". Words such as expects, anticipates, intends, plans, believes, seeks, estimates, and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements may include, among other things, statements regarding future: reserves, production, costs, cash flows, and earnings; drilling locations and growth opportunities; capital investments and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this presentation reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this presentation or accompanying materials, we may use the terms “projection”, “outlook” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in the Annual Report on Form 10-K for the year ended December 31, 2017, filed with the U.S. Securities and Exchange Commission ("SEC") on February 27, 2018 and amended on May 1, 2018, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations, and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this presentation or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

This presentation contains certain non-GAAP financial measures. A reconciliation of each such measure to the most comparable GAAP measure is presented in the Appendix hereto. We use "adjusted cash flows from operations," "adjusted net income (loss)," "adjusted EBITDA“, and “adjusted EBITDAX” and "PV-10," non-GAAP financial measures, for internal reporting and providing guidance on future results. These measures are not measures of financial performance under GAAP. We strongly advise investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure. See the Appendix for a reconciliation of these measures to GAAP. Rate of return estimates do not reflect lease acquisition costs or corporate general and administrative expenses. Non-proved estimates of potentially recoverable hydrocarbons and EURs may not correspond to estimates of reserves as defined under SEC rules. Resource estimates and estimates of non-proved reserves include potentially recoverable quantities that are subject to substantially greater risk than proved reserves.

© 2018 PDC Energy, Inc. All Rights Reserved.

Commonly Used DefinitionsBbl – BarrelBoe – Barrel of oil equivalentBtu – British thermal unitCAGR – Compound Annual Growth RateCWC – Completed well costD&C – Drilling and CompletionsEBITDAX – Earnings before interest, taxes, depreciation, amortization and explorationEUR – Estimated Ultimate RecoveryGross Margin – Oil, gas and NGL sales less LOE, TGP and prod. tax, as a % of oil, gas and NGL salesLeverage Ratio – as defined in our revolving credit facility agreement; similar to Debt to EBITDAXLOE – Lease operating expensesMM – MillionMMcf – Million cubic feetSRL/MRL/XRL – Standard-, Mid- and Extended-reach lateralSWD – Salt-water disposalTGP – Transportation, gathering and processingTIL – Turn-in-line

PDC ENERGY – Strategic Overview

May 2018 3

~13038-42

1.3x

42-45%

~$65

2018e Crude Oil

2018e Production(MMBoe)

2018e Outspend (millions)

Dec. ‘18e Exit Rate(Mboe/d)

YE18e Leverage Ratio

Returns Results Responsibility

Strong Returns on inventory ~2,000 gross locations in the Core Wattenberg and Delaware basins

Prolific Results expected to drive ~25% production growth in 2018 with free cash flow generation in 2H18

Corporate Responsibility focused on sustainable operations and the safe and responsible development of our assets

PDC ENERGY – Company Overview

May 2018 4

$3.9B

453

$5.1B

Market Cap(1)

Enterprise Value(1)

YE17 Proved Reserves

Delaware Basin• ~60,000 net acres(3)

• 450 identified locations(4)

• 98 MMBoe proved reserves

Core Wattenberg• ~100,000 net acres(2)

• 1,500 identified locations(2)

• 351 MMBoe proved reserves

(1) As of 5/8/18; assumes 66 mm shares outstanding; (2) Niobrara and Codell only. Includes Bayswater acquisition locations; (3) Includes ~3,200 net acres in Western area due to expire in 1H18; (4) Some locations subject to higher degree of uncertainty as they are based on downspacing tests the Company is currently in process of testing or has not yet tested.

PDC ENERGY – Track Record of Delivering Value

May 2018 5

0

10

20

30

40

50

2015 2016 2017 2018e

Production (MMBoe)

$5,000

$10,000

$15,000

$20,000

$25,000

2015 2016 2017 2018e

Debt per Flowing Boe

0

100

200

300

400

500

2014 2015 2016 2017

Proved Reserves (MMBoe)

• Proven track record of value-added growth− 35+% 3-year production CAGR

• Remain focused on balance sheet strength− ~40% decrease in debt per flowing Boe

since 2016 Delaware Basin acquisition− YE18e leverage ratio of 1.3x

42-45%

19-22%

32-35%

PDC ENERGY – Portfolio Value Creation

May 2018 6(1) Economics assume current basin differentials curve applied to NYMEX forecast of approximately $62/Bbl and $2.85/Mcf for 2018; $55/Bbl and $2.75/Mcf in 2019+; excludes lease acquisition and corporate level costs. Target MRL CWC approximately $3.5 million in Wattenberg and $11 million in Delaware; (2) Approximately 175 Wattenberg and 50 Delaware MRL equivalent locations.

$9.3 $8.6

$4.4$3.2

$2.1

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

Block 4 North Central Kersey Plains Prairie

mill

ions

Average NPV10 per well by Area (MRL Equivalent)

MRL Equivalent Inventory Breakdown(~1,950 total locations)

Kersey

Plains

Prairie

Block 4

North Central

Other

• Robust inventory of 10-15 years at current development pace

• Entire portfolio delivers strong economic results− Weighted-average portfolio of MRL equivalents delivers F&D costs

of < $8/Boe and IRRs of ~70%

• XRL development further strengthens expected IRRs & NPVs

• Additional upside potential to current well performance− Early-stage development in the Delaware− Prairie and Plains Areas based on industry data

IRR > 100% IRR > 60%IRR > 60%IRR > 40%IRR > 50%

~400

~275

~650

~250

~150

~225(2)

PDC ENERGY – 2018 Financial Guidance Reaffirmed

May 2018 7

$-

$1.00

$2.00

$3.00

$4.00

2015 2016 2017 2018

LOE/Boe

$-

$2.00

$4.00

$6.00

$8.00

2015 2016 2017 2018e

G&A/Boe

$-

$0.50

$1.00

$1.50

2015 2016 2017 2018e

TGP/Boe

2018 Guidance

• Production: 38 – 42MMBoe• Capital Investments: $850 - $920MM

Price Realizations (% NYMEX) (excl. TGP)Oil: 91 – 95%Gas: 55 – 60%NGL: 30 – 35%

$3.40 - $3.70$0.60 - $0.80

$2.75 - $3.00

2018e Commodity Mix

Oil Natural Gas NGLs

42-45%

19-22%

32-35%

PDC ENERGY – Overview of Financial Strength

May 2018 8(1) Assumes weighted-average floor prices

Leverage and Liquidity

• Leverage ratio of 1.7x

• $745 million liquidity − $45 million cash balance− Anticipate exiting 2018 with an undrawn revolver

• 2018e outspend reduced from ~$90 to ~$65 million due to combination of pricing and performance to-date

− 100% of projected outspend is anticipated to be covered by proceeds from Utica divestiture and SaddleButte transaction (~$65 million)

Hedge Portfolio• ~70% of 2Q-4Q18e oil production hedged at ~$51.50/Bbl(1)

− ~1.5 MMBbls of Midland basis swaps at ($0.10/Bbl)

• 8.2 MMBbls 2019 oil hedged at ~$53/Bbl(1)

• ~70% of 2Q-4Q18e gas production hedged at ~$2.95/MMBtu(1)

− Weighted-avg. basis swap of ~($0.45/MMBtu) on ~65% of 2Q-4Q18e gas

• Began layering in 2019 gas hedges at ~$2.75/MMBtu$0

$250

$500

$750

$1,000

2018 2019 2020 2021 2022 2023 2024 2025 2026

Debt Maturity Schedule(millions)

Undrawn Revolver

6.125% Senior Notes

1.125% Convertible

Notes

5.75% Senior Notes

PDC ENERGY – Corporate Social Responsibility

May 2018 9

COMMUNITY OUTREACH

EMPLOYEES MATTER

SAFE OPERATIONS

PDC ENERGY – Expect Strong Balance Sheet with Capital Efficient Growth

• Capital efficient production growth− 3-Year Production CAGR estimated at ~33%− Targeting 30 – 40% production growth in 2019

• Projected YE19 Leverage Ratio of ~1.0x− 2018 expected outspend covered by Utica

divestiture and Saddlebutte proceeds− Anticipate a build in FCF of $100-$200MM in 2019

• Based on six rig pace through 2019 − 3 in Wattenberg and 3 in Delaware

May 2018 10(1) Includes 1Q18 actual results and updated pricing and basis differential assumptions to FY18 outlook.

2017 2018e(1) 2019e

YE Leverage Ratio ~1.9x ~1.3x ~1.0x

Capital Investment (MM) $790 $850 - $920 $950 - $1,050

(Outspend)/FCF ($211mm) (~$65mm) ~$100 - $200mm

Production Profile 31.8 38 – 42 30 – 40% growth

Rig Program (WB/DE) 3/3 3/3 3/3

NYMEX Prices ($/Bbl / $/Mcf) ~$51/$3 $62/$2.85 $55/$3

0.0x

1.0x

2.0x

3.0x

4.0x

0

20

40

60

80

2016 2017 2018e 2019e

Leve

rage

Rat

io

MM

Boe

Production and Leverage Ratio OutlookProduction Range Leverage Ratio

ASSET OVERVIEW

1Q18 Results 76,625 Boe/d 35 Spuds 29 TILs

CORE WATTENBERG – Prolific Asset in Development Mode

May 2018 12(1) Niobrara and Codell only; (2) Includes Bayswater acquisition locations.

100,000

351

1,500~Net Acres(1)

~Horizontal Locations(2)

YE17 Proved Reserves(MMBoe)

CORE WATTENBERG – 2018 Activity Focused on Capital Efficient Development

• Plan to invest $470 - $500 million in 2018− Expect to spud and TIL 135 – 150 wells− Plan to operate three rigs and one completion crew(1)

− Majority of focus in prolific Kersey Area− Initial Prairie wells to be evaluated in reduced line pressure

environment

• Sequential growth expected through remainder of 2018 as midstream expansion comes online

− Average working interest for 2018 TILs expected to be 85+%

• Focus on maintaining low cost structure− Anticipate 2018e LOE/Boe of $2.50 - $2.75− Recent Saddle Butte pipeline agreement delivers

~$24 million in proceeds, strengthens commitment to move more oil volumes on pipe, additional acres dedicated

May 2018 13(1) Second crew scheduled to complete one pad in 2Q18

all numbers approximate SRL MRL XRL

Lateral length (feet) 4,200 6,900 9,500

Drilling Days (spud-to-spud) 6 8 10

% of 2018 spuds 25% 45% 30%

% of 2018 TILs 50% 35% 15%

Completed well cost (millions) $2.6 $3.5 $4.4

CORE WATTENBERG – Production Unbundled with Midstream Expansions

May 2018 14(1) Per DCP Midstream earnings call 5/8/18

• Wattenberg production expected to account for ~75-80% of 2018e volumes

Natural Gas • DCP gathers and processes ~75% of Wattenberg gas• DCP system throughput capacity expected to increase by ~50%

in next 12 months(1)

− Plant 10 (200 mmcf/d) expected TIL in August 2018− Plant 11 (200 mmcf/d + 100 mmcf/d bypass) expected TIL 2Q19− Plant 12 (up to 1 Bcf/d including bypass) – initial TIL expected 2020

• ~25% of 2018e gas to Aka Energy

Oil • Recently executed long-term firm transportation commitment

with Tallgrass Energy − 12,500 Bbls/d with access to refinery destinations and Cushing, OK

• ~70% of infield oil volumes gathered on pipe

DELAWARE BASIN – Primary Focus in Two Oil-Rich Areas

May 2018 15(1) Includes ~3,200 acres in the Western area due to expire in 1H18; (2) Some locations subject to higher degree of uncertainty as they are based on downspacing tests the Company is currently in process of testing or has not yet tested.

60,000

98

450~Net Acres(1)

Est. Block 4 & North CentralMRL Locations(2)

YE17 Proved Reserves(MMBoe)

1Q18 Results 20,690 Boe/d 8 Spuds 7 TILs

DELAWARE BASIN – Focused on Continued Execution

• Anticipate 2018 capital investments of $380 - $420 million− ~75% allocated to spud and TIL 25 – 30 operated wells− ~15% planned for midstream infrastructure investments− ~10% for leasing, non-op and technical studies

• Drilling and completion execution delivering strong sequential production growth

− Focus on artificial lift, choke management and infrastructure investment are paying dividends

− ~135% production growth from 1Q17 to 4Q17− Anticipate FY18 Delaware production to more than double

from FY17

• Focus on water mgmt. helps deliver low-cost operations− 2018 LOE expected to be between $4.00 - $4.50/Boe− Initial water recycling tests planned mid-year

May 2018 16

5,7006,800

10,000

12,900

16,000

20,690

0

5,000

10,000

15,000

20,000

25,000

Dec. '16 1Q17 2Q17 3Q17 4Q17 1Q18

Boe/

d

Delaware Production (Boe/d)

DELAWARE BASIN – Prolific Results Continue in Block 4

May 2018 17

0

100,000

200,000

300,000

400,000

500,000

0 50 100 150 200 250

Boe

Days

Wolfcamp A/B XRL

Buzzard North (A) Buzzard South (B) Grizzly North (B) Grizzly South (A)

• Buzzard and Grizzly wells continue to show strong early performance (~70% oil)

• Drilling last two wells on six-well downspacing test− Grizzly Bear – testing 12 wells per section

equivalent spacing in Wolfcamp A

• Initial Wolfcamp C test drilled (Grizzly West)

Wells Online2018 Expected TILs

Buzzard North

Buzzard South

Elkhead

Kenosha

Argentine

Lost Saddle

Hermit

Blue Lakes

Grizzly South

Grizzly North

Grizzly West

Grizzly Bear (6 Well Downspacing Test)

Approximate Surface Locations

Eastern Area – Block 4

2.0 MMBoe EUR

2.5 MMBoe EUR

DELAWARE BASIN – Solid Early Data from North Central Wells

May 2018 18

• Five 1Q18 TILs in North Central − 3-well Greenwich pad, Sunnyside, Old Monarch, − Three Wolfcamp A’s (2 MRL, 1 SRL)− Two Wolfcamp B’s ( 1MRL, 1 SRL)

• All wells in early flowback stage (< 60 days online)− Each well producing an average of ~1,000 – 1,400

Boe/d(average of all five is ~1,150 Boe/d)

− Averaging ~55% crude oil

• Four expected TILs remaining in 2018− Yellow Jacket and Hornet (same pad)− Greenwich pad (2-wells)

Wells OnlineNon-Op Well2018 Expected Activity

North Central Area

State Lazy Acre

Greenwich 3H/4H

Approximate Surface Locations

Old Monarch

Hornet

Yellow Jacket

Greenwich (3-well pad)

Sunnyside

Greenwich (2-well pad)

Liam State

DELAWARE BASIN – Oil Marketing Summary

May 2018 19

• Delaware oil production expected to account for 20-25% of total PDC 2018e volumes

Oil Gathering• Infield oil is piped and trucked to central delivery points

− ~50% of 2018e oil production is on pipe – directly connected with Oryx (10,000 Bbl/d agreement with Oryx Midstream)

− 2018e investment of ~$20MM in PDC-owned oil gathering system in Block 4

Downstream Marketing• Executed firm sales agreement with marketing division of a large,

international energy company − Provides firm physical takeaway capacity and int’l pricing exposure− 5.5 year agreement provides flow assurance out of Midland

for ~85% of 2018e and 2019e volumes− Eliminates majority of 2018-2019 exposure to Midland differentials− Achieves price diversification by selling at Corpus Christi terminal and realizing

international export-market (Brent blend) pricing

• Anticipate 2018e & 2019e total oil volumes to realize 88-92% NYMEX Source: BTU Analytics

Int’l Price Exposure

DELAWARE BASIN – Gas Gathering Overview

May 2018 20

Eastern Block 4 and South Central Area – Eagle Claw• Volumes processed by Eagle Claw Midstream

and marketed by PDC− 100% of current volumes have firm takeaway

capacity, including:− 40,000 MMbtu/d El Paso transportation to Waha− 40,000 MMbtu/d Firm Sale indexed to Houston Ship

Channel (HSC) with fixed differential through 2019− Actively working to secure additional firm

transportation capacity

North Central Area – ETC • Volumes bought at the wellhead by ETC

and marketed on ETC-owned assets

Source: BTU Analytics

Delaware gas production expected to account for ~20-25% of total PDC 2018e gas volumes

PDC ENERGY – Strategic Overview

May 2018 21

~13038-42

1.3x

42-45%

~$65

2018e Crude Oil

2018e Production(MMBoe)

2018e Outspend (millions)

Dec. ‘18e Exit Rate(Mboe/d)

YE18e Leverage Ratio

Returns Results Responsibility

Strong Returns on inventory ~2,000 gross locations in the Core Wattenberg and Delaware basins

Prolific Results expected to drive ~25% production growth in 2018 with free cash flow generation in 2H18

Corporate Responsibility focused on sustainable operations and the safe and responsible development of our assets

Investor RelationsMike Edwards, Senior Director Investor Relationsmichael.edwards@pdce.comKyle Sourk, Manager Investor Relationskyle.sourk@pdce.com

Corporate HeadquartersPDC Energy, Inc.1775 Sherman StreetSuite 3000Denver, Colorado 80203303-860-5800

Websitewww.pdce.com

APPENDIX

DELAWARE BASIN – Water Management Improves Efficiencies

May 2018 24

• Water mgmt. delivers incremental value options− Better operational control and synergies− Reduced LOE and/or capital per well

• More than 90% of produced water volumes transported via pipe in 1Q18

− Central Area wells utilize PDC water lines and SWDs

Completion-Water Distribution System• 24” trunk line through center of acreage

− Capable of delivering enough treated water to support two frac crews

• Water treatment facility under construction− Two treated water pits (375 MBbls capacity per pit) − One SWD well in Block 4 (30 MBbls/d capacity)

• Utilized ~20% recycled water in Kenosha/Elkheadwells

• Substantial reuse of recycled water planned for completions of Grizzly Bear Pad

Buzzard North

Buzzard South

Elkhead

Kenosha

Argentine

Lost Saddle

Hermit

Blue Lakes

Grizzly South

Grizzly North

Grizzly West

Grizzly Bear (6 Well Downspacing Test)

Approximate Surface Locations

Eastern Area – Block 4 – Water Distribution System

PDC SWDPDC Planned SWD3rd Party SWD

Fresh Water Pit

Treated Water Pits

24” Water Distr. Line

Water Gathering Line

Reconciliation U.S. Non-GAAP

May 2018 25

Adjusted EBITDAX

Three Months Ended

March 31, 2018 2017 Net income (loss) to adjusted EBITDAX:

Net income (loss) $ (13.1 ) $ 46.1

(Gain) loss on commodity derivative instruments 47.2 (80.7 ) Net settlements on commodity derivative instruments (26.0 ) 0.5

Non-cash stock-based compensation 5.3 4.5

Interest expense, net 17.4 19.2

Income tax expense (benefit) (4.6 ) 26.3

Impairment of properties and equipment 33.2 2.2

Exploration, geologic, and geophysical expense 2.6 1.0

Depreciation, depletion, and amortization 126.8 109.3

Accretion of asset retirement obligations 1.3 1.8

Adjusted EBITDAX $ 190.1 $ 130.2

Cash from operating activities to adjusted EBITDAX:

Net cash from operating activities $ 205.1 $ 139.5

Interest expense, net 17.4 19.2

Amortization of debt discount and issuance costs (3.2 ) (3.2 ) Gain (loss) on sale of properties and equipment (1.4 ) 0.2

Exploration, geologic, and geophysical expense 2.6 1.0

Other (0.2 ) (0.7 ) Changes in assets and liabilities (30.2 ) (25.8 ) Adjusted EBITDAX $ 190.1 $ 130.2

Reconciliation U.S. Non-GAAP

May 2018 26

Adjusted Cash Flows from Operations

Three Months Ended

March 31, 2018 2017 Adjusted cash flows from operations:

Net cash from operating activities $ 205.1 $ 139.5 Changes in assets and liabilities (30.2 ) (25.8 )

Adjusted cash flows from operations $ 174.9 $ 113.7

Adjusted Net Income (Loss)

Three Months Ended

March 31, 2018 2017 Adjusted net income (loss):

Net income (loss) $ (13.1 ) $ 46.1

(Gain) loss on commodity derivative instruments 47.2 (80.7 ) Net settlements on commodity derivative instruments (26.0 ) 0.5

Tax effect of above adjustments (5.1 ) 30.0

Adjusted net income (loss) $ 3.0 $ (4.1 ) Weighted-average diluted shares outstanding 66.0 66.1

Adjusted diluted earnings per share $ 0.05 $ (0.06 )