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ENERCOM’S THE OIL AND GAS CONFERENCE August 14, 2017
Forward-Looking Statements
This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding the company’s business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates, guidance, vision and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: the recent Delaware Basin acquisitions; estimated future production (including the components of such production), sales, expenses, cash flows, liquidity and balance sheet attributes (including leverage ratios); estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves; the impact of prolonged depressed commodity prices, including potentially reduced production and associated cash flow; anticipated capital projects, expenditures and opportunities; expected capital budget allocations; operational flexibility and ability to revise development plans, either upward or downward; availability of sufficient funding and liquidity for the capital program and sources of that funding; expected net settlements on derivatives for 2017; future exploration, drilling and development activities, including non-operated activity, the number of drilling rigs expected to run and lateral lengths of wells; expected 2017 production and timing of turn-in-lines; potential for future impairments; expected expansion of gas processing systems and expected line pressure; compliance with debt covenants; impact of litigation on the results of operations and financial position and future strategies, plans and objectives, including all multi-year forecasts and activity projections through 2019.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements made in this presentation reflect PDC’s good faith judgment, such statements can only be based on facts and factors currently known to PDC. 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, the Company uses the terms “outlook,” “projection”, “vision” or similar terms or expressions, to indicate that it has “modeled” certain future scenarios. PDC typically uses these terms to indicate its current thoughts on possible outcomes relating to its business or the industry in periods beyond the current fiscal year. In addition to being subject to additional levels of uncertainty generally, forward-looking statements regarding such prospective matters do not necessarily reflect the outcomes the Company views as the most likely to occur, but instead are shown to illustrate aspects of its business in the context of a variety of scenarios it believes to be plausible.
PDC urges you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, and PDC’s other filings with the U.S. Securities and Exchange Commission (”SEC”), which are incorporated by this reference as though fully set forth herein, for further information on risks and uncertainties that could affect the Company's business, financial condition, results of operations and cash flows. The Company cautions you not to place undue reliance on forward-looking statements, which speak only as of the date hereof. PDC undertakes 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.
© 2017 PDC Energy, Inc. All Rights Reserved.
8/14/2017 2
< 2.0x Leverage Ratio(1)
(2017-2019)
PDC Energy – Strategic Overview
(1) Leverage Ratio is defined in revolving credit facility agreement; (2) Excludes Transportation, Gathering and Processing (TGP); (3) Well-head economics assumes base case pricing, reflects basin differentials and excludes G&A
~35% 3-year
Production CAGR (2016-2019)
< $3 2017e Corporate
LOE/Boe
< $4 Avg. Corporate Oil
Differentials(2) ($/Bbl)
15% Watt. Drilling
Efficiency Gains
2,600 ~ Drilling Inventory
Top-Tier Growth Profile
Financial Discipline
Technical Innovations
Marketing & Midstream
Shareholder Value Creation
Capital Efficient Drilling
Strategic Overview
8/14/2017 3
PDC Energy – Premier Assets Provide Top-Tier Growth
(1) As of 8/11/17; assumes 65.9 mm shares outstanding; (2) YE16 – ~700 proved and ~1,100 probable; (3) As of YE16 – Reflects 5,000’ laterals in Eastern and Central areas and 10,000’ laterals in Western area
32 – 33 2017e Production (MMBoe)
153 2017e TILs
341 YE16 Proved Reserves (MMBoe)
40+% 2017e Annual Production Growth
$2.7B Market Cap(1)
2,600 ~ Horizontal Locations
Enterprise Value(1)
$3.8B
Core Wattenberg • ~95,500 net acres
• 1,800 identified locations(2)
• 305 MMBoe proved reserves
Delaware Basin • ~60,000 net acres
• 785 identified locations(3)
• 33 MMBoe proved reserves
Utica Shale
8/14/2017 4
PDC Energy – Track Record of Delivering Value
32-33 MMBoe 22.2 MMBoe 15.4 MMBoe 9.3 MMBoe
0
5
10
15
2014 2015 2016 2017e
Oil Production (MMBbls)
2014 2015 2016 2017e
$0
$5
$10
$15
$20
$25
2014 2015 2016 2017e
Operating Costs ($/Boe) LOE per BOE TG&P Production Taxes G&A
8/14/2017
$0
$20
$40
$60
$80
$100
0%
20%
40%
60%
80%
100%
2014 2015 2016 2017e
NYM
EX O
il ($
/Bb
l)
Gro
ss M
argi
n (
%)
Gross Margin(2)
Gross Margin NYMEX Oil
(1) Excludes fees related to Delaware Basin acquisition; (2) Gross margin is defined as oil gas and NGL sales less LOE, TGP and production tax, expressed as a percent of oil, gas and NGL sales 5
(1)
PDC Energy – Second Quarter Results
8/14/2017 (1) Leverage ratio is defined in revolving credit facility agreement
$2.50 LOE/Boe
62% Year-over-Year Oil Prod. Increase
(Bbls/d)
88,078 (Boe/d)
15% Wattenberg Drilling Efficiency
Improvements
• Continued execution in Wattenberg drives strong results
─ Drill times improved ~15% on SRL, MRL and XRL wells
─ Wattenberg LOE reduced 17% from 2Q16 to $2.22/Boe
─ ~75,620 Boe/d 2Q17 production
• Solid Results in Delaware program
─ ~10,050 Boe/d represents ~50% production increase (2Q17 v 1Q17; 6 TILs; 5 spuds
─ New Eastern and Central Area wells producing above type curves
─ Infrastructure investment delivering PDP production optimization in Central Area
─ 2Q17 midstream investment of $7 million
• Continued focus on strong financial positioning
─ Liquidity of $902 million
─ Leverage ratio(1) improved to 1.9x
─ Robust hedge positions enable predictability of margins
2017 Second Quarter Highlights
6
PDC Energy – Capital Efficiency in a $50 and $3 World
8/14/2017 7
2017 - 2019: Mid-Year $50/$3 Case vs. Analyst Day Base Case:
• Expect to maintain six rig pace through 2019 compared to acceleration to 11 rigs in AD Base Case
• ~$400 million reduction in 3-year total capital spend
• Anticipate cash flow neutrality in 2019 at $50/Bbl NYMEX
• Projected YE19 Leverage Ratio of 1.1x vs 0.9x in AD Base Case
─ $50/Bbl vs $61/Bbl NYMEX in AD Base Case
• Capital efficient production growth
─ 2019e production only <5% below AD Base Case projections
─ ~35% 3-year CAGR (‘16-’19)
$50/Bbl and $3/Mcf NYMEX Prices Held Flat
(1) Assumes $700 million revolving credit facility
$50/Bbl and $3/Mcf NYMEX 2017e 2018e 2019e
YE Leverage Ratio ~1.8x ~1.6x ~1.1x
Capital Investment (MM) ~$800 $850 - $900 $900 - $1,000
Outspend (Capex/Cash Flow) ~45% ~25% ~0%
YE Cash/(Revolver) (MM) $100 - $150 (0 – 15% drawn)(1) (0 – 15% drawn)(1)
Production Profile ~32 MMBoe
(~45% YoY growth)
20 – 30% growth 30 – 40% growth
Rig Program (WB/DE) 3/3 3/3 3/3
0.0x
1.0x
2.0x
3.0x
4.0x
0
20
40
60
80
2016 2017e 2018e 2019e
Leve
rage
Rat
io
MM
Bo
e
Production and Leverage Ratio Outlook Production Range Leverage Ratio
PDC Energy – 2017 Production & Capital Guidance
~95,000 December ‘17 Exit Rate (Boe/d)
153 2017e TILs
179 2017e Spuds
~50% Year-Over-Year Increase in Oil Production
2017e Production Mix Wattenberg • Plan to return to 3 rigs in 4Q17 • ~30% annual production growth • 155 Spuds • 133 TILs with ~7,300’ avg. lateral length • 86% WI
Delaware
• Maintain 3 rig pace through remainder of 2017 • 24 Spuds • 20 TILs with ~7,900’ avg. lateral length • 92% WI
2017e Production (MMBoe) Anticipate Closer to 32 MMBoe
Production Growth
Increase in Lateral Feet Drilled
8/14/2017
~40% Oil
~37% Gas
~23% NGL
8
PDC Energy – 2017 Capital Investment Program and Financial Guidance
(1) Includes ~$40 million proceeds from sale of MK note. (2) G&G = Geologic and Geophysical
$0.70 - $0.90 TGP/Boe
$3.25 - $3.60 G&A/Boe
$2.65 - $3.00 LOE/Boe
$15.00 - $16.50 DD&A/Boe
2017e Capital Investments
Wattenberg Delaware Delaware Midstream
Capital Investment Details • 2017e capital investment of ~$800 MM
• Wattenberg: ~$450 MM • Delaware: ~$345 MM
− Includes $35 MM midstream, $30MM leasing & seismic
• Exploration and G&G(2) expense: $5-10 MM
Price Realizations • Oil: 92 – 94% • Gas: 70 – 72% • NGL: 27 – 31% • Production tax: 6 – 8% of sales
2017e Capital Investment (millions)
YE17e Cash Balance(1) (millions)
YE17e Leverage Ratio(1)
8/14/2017 9
Robust Hedge Position Insulates Capital Program
10
CIG Basis Swaps – 2H17: 25,128 BBtu hedged at ($0.33) off NYMEX; 2018: 30,200 BBtu hedged at ($0.34) off NYMEX Waha Basis Swaps – 2018: 6,000 BBtu hedged at ($0.50) off NYMEX Propane Hedges – 2H17: 31.8 million gallons at $0.64/gallon; 2018: 12.0 million gallons at $0.65/gallon
2017 and 2018 Hedges in Place as of 6/30/17 Plus Hedges Entered Into prior to August 3, 2017
8/14/2017
NATURAL GAS
2H17 2018
Volumes (BBtu)
Collar 5,900 5,230
Swap 19,620 51,280
Total Natural Gas Hedged 25,520 56,510
Natural Gas Price ($/Mmbtu)
Floor $3.38 $3.00
Ceilings $4.02 $3.54
NYMEX Swap $3.40 $2.95
Weighted Average Price (floor) $3.40 $2.95
CRUDE OIL
2H17 2018
Volumes (MMBbls)
Collar 1.2 1.5
Swap 3.7 7.0
Total Crude Oil Hedged 4.9 8.5
Crude Oil Price ($/Bbl)
Floor $49.54 $41.85
Ceilings $62.32 $54.31
NYMEX Swap $50.13 $52.34
Weighted Average Price (floor) $49.98 $50.47
PDC Energy – Balance Sheet Strength and Liquidity
Leverage and Liquidity
• $902 million liquidity
• $202 million cash balance
• Leverage ratio(1) of 1.9x
Debt Maturities
• $700 million credit facility due May 2020
• $200 million 1.125% convertible notes due Sept. 2021
• $500 million 7.75% senior notes due Oct. 2022
• $400 million 6.125% senior notes due Sept. 2024
Corporate Ratings
• Moody’s – B1 (“Positive Outlook”)
• S&P – B+ (“Positive Outlook”)
As of June 30, 2017
(1) Leverage ratio is defined in revolving credit facility agreement
$0
$250
$500
$750
$1,000
2017 2018 2019 2020 2021 2022 2023 2024
Debt Maturity Schedule (millions)
Undrawn Revolver
1.125% Convertible Notes 6.125% Senior Notes
7.75% Senior Notes
8/14/2017 11
ASSET OVERVIEW
Core Wattenberg – Asset Overview
(1) ~700 proved and ~1,100 probable locations; (2) TIL = turn-in-line; SRL = standard-reach lateral, MRL = mid-reach lateral, XRL = extended-reach lateral
133 2017e TILs
155 2017e Spuds
305 YE16 Proved Reserves (MMBoe)
7,300’ Avg. 2017e TIL (Lateral Feet)
Inner Core
Middle Core
Outer Core ~ Net Acres
~ Acreage HBP
Horizontal Locations(1)
XRL 46%
MRL 24%
SRL 30%
2017e TIL Breakdown(2)
Kersey Area
8/14/2017 13
Core Wattenberg – Drilling Efficiencies
8/14/2017 14
• Continued improvement in spud-to-spud drill times
─ SRL = 6 days
─ MRL = 8 days
─ XRL = 10 days
• Expect to spud 155 wells and TIL 133 wells in 2017
─ Original plan estimated 139 spuds and 139 TILs
─ Anticipate managing TILs in 4Q17
• Three rig program drills the same lateral feet as 3.75 rig program compared to Analyst Day
All numbers approximate SRL MRL XRL SRL MRL XRL
Lateral Length 4,200’ 6,900’ 9,500’ 4,200’ 6,900’ 9,500’
Drilling days (spud-to-spud) 7 10 12 6 8 10
FY17e Operated Spuds 50 51 38 47 62 46
Lateral Feet Drilled (000’s) 210 352 361 197 428 437
FY17e Operated TILs 50 41 48 40 31 62
12
7 7 6
0
5
10
15
2015 2016 1H17 2H17
Day
s
SRL
18
11 10
8
0
5
10
15
20
2015 2016 1H17 2H17
Day
s
MRL
-
14
12
10
0
5
10
15
2015 2016 1H17 2H17
Day
s
XRL
2017 Analyst Day 2Q17 Earnings Call
STANDARD-REACH LATERALS
• Completion design with 170’ spacing showing modest outperformance in early days
─ Previous method based on 200’ - 225’ spacing
• ~22 SRL TILs planned in 2H17
0
50,000
100,000
150,000
200,000
0 30 60 90 120 150 180 210
Cu
mu
lati
ve G
ross
2-P
has
e P
rod
uct
ion
pe
r 9
,50
0 (
Bo
e)
Days
0
25,000
50,000
75,000
100,000
RowLabels
30 60 90 120 150 180 210
Cu
mu
lati
ve G
ross
2-P
has
e P
rod
uct
ion
pe
r 4
,20
0‘ (
Bo
e)
Days
Core Wattenberg – Encouraging Completion Enhancements
8/14/2017 15
EXTENDED-REACH LATERALS
• Early results testing 140’ completion spacing show production uplift
• Economic benefit outweighs additional completion cost
• ~30 XRL TILs planned in 2H17
1,100 MBoe EUR Type Curve (based on 170’ spacing) 140’ Completion Spacing
490 MBoe EUR Type Curve (based on 225’ spacing) 170’ Completion Spacing
Core Wattenberg – Midstream Overview
8/14/2017
NATURAL GAS
• Multiple midstream providers (DCP and Aka-APC)
─ DCP expected to gather and process ~72% of 2017e gas volumes
• DCP current capacity ~850 MMcf/d
• Working with midstream providers regarding potential additional processing/gathering capacity
OIL
• Ample takeaway capacity projected through 2020
• Minimal firm commitments enable competitive pricing opportunities
Additional Capacity Enables Future Growth Objectives
(1) Source: DCP Midstream press release, 1/4/17
Additional Compression 2018-2019 Processing Capacity Expansions
Grand Pkwy
Plant 10
Plant 11
DCP Planned Expansions(1)
• + 40 MMcf/d bypass (in-service July 2017) • +200 MMcf/d plant 10 (year-end 2018) • +200 MMcf/d plant 11 (mid-year 2019)
16
Delaware Basin – Asset Overview
(1) YE16 – Reflects 5,000’ laterals in Eastern and Central areas and 10,000’ laterals in Western area
30% YE16 HBP
20 2017e TILs
24 2017e Spuds
3,000+ Potential Hz Locations(2)
~ Net Acres
Average Working Interest
Horizontal Locations(1)
Eastern
Central Western
8/14/2017
Western Central Eastern
EUR (MBoe) 1,200 1,000 – 1,400 750 – 1,000
Working Int. 100% 87% 91%
Gas NGL
17
Delaware Basin – 2017 Planned Activity and Recent Wells
8/14/2017
• $280 million D&C budget ─ Spud 24 wells
─ 15 spuds in Eastern
─ 7 spuds in Central
─ 2 spuds in Western
─ TIL 20 wells including 9 XRLs
• $35 million midstream infrastructure ─ Add SWD wells and capacity
─ Drill water supply well and construct frac pits
─ Install gas gathering lines
• $30 million leasing, seismic & tech studies
Eastern
Central Western
PDC – Grizzly (3) Wolfcamp B-2, A-1
~5K’-1, ~10K’-2 laterals
PDC/Arris – Greenwich 2 well pad - Wolfcamp A & B
~7,500’ laterals
PDC/Arris – Kenosha Wolfcamp A
~10,000’ lateral
PDC – Phillips State Wolfcamp A
~7,500’ lateral
Rig Location
PDC – Lost Saddle Wolfcamp A
~5,000’ lateral
18
0
100,000
200,000
300,000
400,000
500,000
0 60 120 180 240 300 360 420
Gro
ss C
um
ula
tive
2-P
has
e P
rod
uct
ion
pe
r 5
,00
0' o
f La
tera
l (B
OE)
Days
Sugarloaf
Keyhole
Hanging H
Argentine
Kenosha
Lost Saddle
Average
Delaware Basin – Prolific Eastern Area Well Results
8/14/2017 19
• Kenosha well (1st PDC operated 10,000’ lateral)
─ 30-day peak IP: 2,295 Boe/d (~230 Boe per 1,000’)
─ ~2,000 Boe/d for 100 straight days
─ ~1,000 Bbls/d oil production for 100 straight days
─ 50% oil mix (2-phase)
• Plan to TIL seven wells in Eastern area in 2H17
─ Six 10,000’ laterals
1
10
100
1000
10000
0 20 40 60 80 100 120
Bo
e/d
Days
Kenosha Daily Performance Eastern Area – Wolfcamp A
1,000 MBoe EUR Type Curve
0
100,000
200,000
300,000
0 60 120 180 240 300 360 420G
ross
Cu
mu
lati
ve 2
-Ph
ase
Pro
du
ctio
n p
er
5,0
00
' of
Late
ral (
BO
E)
Days of Production
Liam State
HSS State
Greenwich 4H
Greenwich 3H
Delaware Basin – Recent Central Area Wells Exceeding Type Curve
8/14/2017 20
Central Area Well Highlights
• Greenwich 4H (7,500’ Wolfcamp A)
─ 30-day peak IP: 1,425 Boe/d (190 Boe/d per 1,000’)
─ ~55% oil (2-phase)
• Greenwich 3H (Wolfcamp B)
─ ~1,200’ of lateral was completed
─ 295 Boe/d per 1,000’
• Recently spud three additional Greenwich wells
• Liam State continues to clean up after compression upgrade and tubing pull
─ ~300 BBls/d oil and 3 MMcf/d gas over past week
Central Area – Wolfcamp A/B
Average cumulative production of 4 Central wells
is 15+% above type curve
1,050 MBoe EUR Type Curve
0
500
1,000
1,500
2,000
2,500
12/6/2016 1/6/2017 2/6/2017 3/6/2017 4/6/2017 5/6/2017 6/6/2017 7/6/2017
Bo
e/d
PDP Production Optimization (Tisdale Line and Compression Upgrades)
Delaware Basin – Operating Efficiencies and Midstream Investments
8/14/2017 21
• Integration initiatives and facility upgrades/investments since time of acquisition have led to increased PDP in Central area
• February: Gas line upgrade
─ Replaced ~12 miles of poly gas lines with steel lines
─ Increased operational pressure capabilities
• April: Second Westeros compression upgrade
─ Increased capacity from ~10 MMcf/d to ~20 MMcf/d
─ Enable production optimization projects (lower LOE)
• June: Additional compression added
─ Increased capacity from ~20 MMcf/d to ~40 MMcf/d
─ Ample capacity for near-term development plan
Includes seven legacy wells: Jaymac, Ron, Tisdale, Helbing (2), Winchester and Atlantis
Marketing & Midstream – Gas Throughput and Processing Overview
Eagle Claw
• Current capacity of ~320 MMcf/d
─ Planned expansion in 9/17 & 1/18 – total incremental 400 MMcf/d
Energy Transfer (ETC)
• ETC in northern acreage of Central area (current capacity of ~1,000 MMcf/d)
─ PDC owned Westeros compressor station expansion recently completed
Western Gas (WES)
• Current capacity of ~800 MMcf/d with planned expansions at both Ramsey and Mentone facilities
Gas delivered to both El Paso and Waha markets
Eastern
Central Western
8/14/2017
Western Gas
ETC/
Undedicated
Eagle Claw
3rd Party Midstream Central Delivery Points
PDC Gas Gathering
Asset YE16 17e Adds Total
Gas Gathering (miles) 60 37 97
Produced Water Pipeline (miles) 35 35 70
SWD Wells 5 3 8
Compression Facilities 5 (1) 4
Fresh Water Pits 10 3 13
Acquired Assets + 2017 Infrastructure Investment
Added 40,000 MMBtu/d firm transportation basin to Waha through 2020
22
Long-Term Delaware Midstream Vision – Roadmap to Incremental Value Creation
Long-Term: Evaluate midstream ownership options – 100% ownership, Joint Venture, potential full or partial monetization
Create separate fee structures for in-field midstream services
Crude oil gathering systems with initial focus on Eastern area
Long-Term: Evaluate potential 3rd party volumes and options to operate and/or participate in gas processing plants and related infrastructure
Fresh water supply distribution options and potential produced water recycling systems
Build out PDC midstream assets & infrastructure to support development plans – 100% PDC owned
Key Objectives
8/14/2017
Key Evaluations
23
< 2.0x Leverage Ratio(1)
(2017-2019)
PDC Energy – Key Takeaways
(1) Leverage Ratio is defined in revolving credit facility agreement; (2) Excludes Transportation, Gathering and Processing (TGP); (3) Well-head economics assumes base case pricing, reflects basin differentials and excludes G&A
~35% 3-year
Production CAGR (2016-2019)
< $3 2017e Corporate
LOE/Boe
< $4 Avg. Corporate Oil
Differentials(2) ($/Bbl)
15% Watt. Drilling
Efficiency Gains
2,600 ~ Drilling Inventory
Top-Tier Growth Profile
Financial Discipline
Technical Innovations
Marketing & Midstream
Shareholder Value Creation
Capital Efficient Drilling
Strategic Overview
8/14/2017 24
Investor Relations Mike Edwards, Senior Director Investor Relations
Kyle Sourk, Manager Investor Relations
Corporate Headquarters PDC Energy, Inc. 1775 Sherman Street Suite 3000 Denver, Colorado 80203 303-860-5800
Website
www.pdce.com
APPENDIX
Kersey Area – Growing Oil Volumes
• Oil volumes per well continue to grow
• GOR typically stabilizes after 18-36 months
• MRL and XRL wells represent recent completion design improvements
─ SRL 490 MBoe EUR still based on 2015 completion design
─ SRL upside projects 600 MBoe EUR (based on % improvement similar to MRL and XRL type curves)
• SRL, MRL and XRLs represent 36%, 29% and 35% of 2017 planned Wattenberg development (TILs)
Based on Previous Analyst Day Type Curves
(1) Oil volumes based on EURs and % oil disclosed at previous Analyst Days
0
2
4
6
8
10
12
2014 2015 2016 2017e
Wattenberg Oil Production (MMBbls)
2015 2016 2017 2015 2016 2017 2016 2017
SRL
MRL
XRL
SRL potential upside w/ new completions
185 175 160
180-200
250 245 255
305
350 Oil Volume per Well(1)
(MBbls)
8/14/2017 27
High GOR 30% Oil
Low GOR 34% Oil
High GOR 30% Oil
Low GOR 34% Oil
96%
51%
Economic Sensitivity Comparison of Type Well IRRs and GOR Variability
$40 / $2.50 Stress Pricing Upside Pricing(2)
Wattenberg Kersey Area – XRL Type Curve at 1,100 MBoe Increased Type Curve from 850 MBoe to 1,100 MBoe in 2017
(1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in 2018-2020 and NYMEX oil of $53, $55, $60, $65/bbl in 2017-2020; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in 2017-2020.
3-Phase EUR: 1,100 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 9,500’
Capital Cost: $4.5MM IRR: 100+% PV10: $8.6MM Undiscounted ROI: 4.3 Payout (months): 9
Base Case Type Well Details(1)
• Approximately 210 currently identified Middle Core locations
─ Increased inventory driven by 2016 acreage trade
• Drill times average 10 days spud-to-spud
• Significantly enhances efficient development of Wattenberg acreage position
Wattenberg XRL Performance PDC Wells Drilled Since 2016 in Kersey Focus Area
Older PDC Operated Wells Updated Completion & Flowback 1,100 MBoe XRL Type Curve
100+%
Not to scale
8/14/2017
100+%
28
3-Phase EUR: 800 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 6,900’
Capital Cost: $3.5MM IRR: 100+% PV10: $6.4MM Undiscounted ROI: 4.2 Payout (months): 10
• Recently completed wells are outperforming type curve
• Over 380 currently identified Middle Core locations
─ Increased inventory driven by 2016 acreage trade
• Drill times average 8 days spud-to-spud
Wattenberg Kersey Area – MRL Type Curve at 800 MBoe Increased Type Curve from 685 MBoe to 800 MBoe in 2017
(1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in 2018-2020 and NYMEX oil of $53, $55, $60, $65/bbl in 2017-2020; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in 2017-2020.
Wattenberg MRL Performance PDC Wells Drilled Since 2015 in Kersey Focus Area
Older PDC Operated Wells Updated Completion & Flowback 800 MBoe MRL Type Curve
High GOR 30% Oil
Low GOR 34% Oil
High GOR 30% Oil
Low GOR 34% Oil
84%
100+%
100+%
43%
Economic Sensitivity Comparison of Type Well IRRs and GOR Variability
$40 / $2.50 Stress Pricing Upside Pricing(2)
Not to scale
8/14/2017
Base Case Type Well Details(1)
29
3-Phase EUR: 490 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 4,200’
Capital Cost: $2.5MM IRR: 100+% PV10: $3.6MM Undiscounted ROI: 3.5 Payout (months): 11
Wattenberg Kersey Area – SRL Type Curve of 490 MBoe
• Began testing tighter stage spacing in 2017
• Potential upside due to new completion design being used on MRL and XRL wells
• Over 800 currently identified Middle Core locations
• Drill times average 6 days spud-to-spud
Type Curve Remains 490 MBoe
(1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf flat in 2018-2020 and NYMEX oil of $53, $55, $60, $65/bbl 2017-2020; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in 2017-2020
Wattenberg SRL Performance PDC Wells Drilled Since 2015 in Kersey Focus Area
Older PDC Operated Wells Updated Completion & Flowback 490 MBoe SRL Type Curve
High GOR 30% Oil
Low GOR 34% Oil
High GOR 30% Oil
Low GOR 34% Oil
60%
100+%
100+%
30%
Economic Sensitivity Comparison of Type Well IRRs and GOR Variability
$40 / $2.50 Stress Pricing Upside Pricing(2)
Not to scale
8/14/2017
Base Case Type Well Details(1)
30
Reconciliation of Non-U.S. GAAP Financial Measures
8/14/2017 31 (1) Other includes the impact of provisions for the uncollectible notes receivable in the three and six months ended June 30, 2017, and the six months ended June 30, 2016.
Net income (loss) to adjusted EBITDAX Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Net income (loss) $ 41.3 $ (95.5) $ 87.4 $ (167.0)
(Gain) loss on commodity derivative instruments (57.9) 92.8 (138.6) 81.7
Net settlements on commodity derivative instruments 12.0 53.3 12.5 120.2
Non-cash stock-based compensation 5.4 6.4 9.8 11.1
Interest expense, net 18.9 10.5 38.1 20.8
Income tax provision (benefit) 24.5 (58.3) 50.9 (100.2)
Impairment of properties and equipment 27.6 4.2 29.8 5.2
Exploration, geologic and geophysical expense 1.0 0.2 2.0 0.4
Depreciation, depletion, and amortization 126.0 107.0 235.3 204.4
Accretion of asset retirement obligations 1.7 1.8 3.4 3.6
Adjusted EBITDAX $ 200.4 $ 122.4 $ 330.6 $ 180.2
Weighted-average diluted shares outstanding 66.0 46.7 66.1 44.2
Adjusted EBITDAX per diluted share $ 3.04 $ $2.62 $ 5.00 $ $4.08
Cash from operating activities to adjusted EBITDAX Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Net cash from operating activities $ 123.7 $ 96.6 $ 263.2 $ 197.8
Interest expense, net 18.9 10.5 38.1 20.8
Amortization of debt discount and issuance costs (3.2) (1.3) (6.4) (3.1)
Gain (loss) on sale of properties and equipment 0.5 (0.3) 0.7 (0.2)
Exploration, geologic and geophysical expense 1.0 0.2 2.0 0.4
Other(1) 40.3 0.7 39.6 (41.3)
Changes in assets and liabilities 19.2 16.0 (6.6) 5.8
Adjusted EBITDAX $ 200.4 $ 122.4 330.6 180.2
Weighted-average diluted shares outstanding 66.0 46.7 66.1 44.2
Adjusted EBITDAX per diluted share $ 3.04 $ $2.62 $ 5.00 $ $4.08
Reconciliation of Non-U.S. GAAP Financial Measures
8/14/2017 32
Net income (loss) to adjusted net income (loss) Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Net income (loss) $ 41.3 $ (95.5) $ 87.4 $ (167.0)
(Gain) loss on commodity derivative instruments (57.9) 92.8 (138.6) 81.7
Net settlements on commodity derivative instruments 12.0 53.3 12.5 120.2
Tax effect of above adjustments 17.2 (55.6) 47.2 (76.8)
Adjusted net income (loss) $ 12.5 $ (5.0) $ 8.5 $ (41.9)
Weighted-average diluted shares outstanding 66.0 46.7 66.1 44.2
Adjusted earnings per diluted share $ 0.19 $ (0.11) $ 0.13 $ (0.95)
Net cash from operating activities to adjusted cash
flows from operations
Three Months Ended
June 30,
Six Months Ended
June 30,
2017 2016 2017 2016
Net cash from operating activities $ 123.7 $ 96.6 $ 263.2 $ 197.8
Changes in assets and liabilities 19.2 16.0 (6.6) 5.8
Adjusted cash flows from operations $ 142.9 $ 112.6 $ 256.6 $ 203.6
